Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Jan. 31, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | mur | ||
Entity Registrant Name | MURPHY OIL CORP /DE | ||
Entity Central Index Key | 717,423 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 5,467,321,679 | ||
Entity Common Stock, Shares Outstanding | 172,396,581 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | [1] | |
Current assets | ||||
Cash and equivalents | $ 872,797 | $ 283,183 | ||
Canadian government securities with maturities greater than 90 days at the date of acquisition | 111,542 | 173,288 | ||
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2016 and 2015 | 357,099 | 522,672 | ||
Inventories, at lower of cost or market | 127,071 | 166,788 | ||
Prepaid expenses | 63,604 | 212,962 | ||
Assets held for sale | 27,070 | 38,340 | ||
Total current assets | 1,559,183 | 1,397,233 | ||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,607,815 in 2016 and $11,924,193 in 2015 | 8,316,188 | 9,818,365 | ||
Deferred charges and other assets | 420,489 | 278,214 | ||
Total assets | 10,295,860 | 11,493,812 | ||
Current liabilities | ||||
Current maturities of long-term debt | 569,817 | 18,881 | ||
Accounts payable | 784,975 | 1,529,848 | ||
Income taxes payable | 13,920 | 4,819 | ||
Other taxes payable | 28,167 | 38,498 | ||
Other accrued liabilities | 102,777 | 75,286 | ||
Liabilities associated with assets held for sale | 2,776 | 7,297 | ||
Total current liabilities | 1,502,432 | 1,674,629 | ||
Long-term debt, including capital lease obligation | 2,422,750 | 3,040,594 | ||
Deferred income taxes | 69,081 | 239,811 | ||
Asset retirement obligations | 681,528 | 793,474 | ||
Deferred credits and other liabilities | 617,490 | 438,576 | ||
Liabilities associated with assets held for sale | [2] | 85,900 | ||
Stockholders' equity | ||||
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | ||||
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2016 and 2015 | 195,056 | 195,056 | ||
Capital in excess of par value | 916,799 | 910,074 | ||
Retained earnings | 5,729,596 | 6,212,201 | ||
Accumulated other comprehensive loss | [3] | (628,212) | (704,542) | |
Treasury stock | (1,296,560) | (1,306,061) | ||
Total stockholders' equity | 4,916,679 | 5,306,728 | ||
Total liabilities and stockholders' equity | $ 10,295,860 | $ 11,493,812 | ||
[1] | Reclassified to conform to current presentation. See Note B for additional information. | |||
[2] | Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. | |||
[3] | All amounts are presented net of income taxes. |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
CONSOLIDATED BALANCE SHEETS [Abstract] | ||
Maturity of Canadian government securities | 90 days | 90 days |
Accounts receivable, allowance for doubtful accounts | $ 1,605 | $ 1,605 |
Property, plant and equipment, accumulated depreciation, depletion and amortization | $ 12,607,815 | $ 11,924,193 |
Cumulative Preferred Stock, par value (per share) | $ 100 | $ 100 |
Cumulative Preferred Stock, authorized shares | 400,000 | 400,000 |
Cumulative Preferred Stock, shares issued | 0 | 0 |
Common Stock, par value (per share) | $ 1 | $ 1 |
Common Stock, authorized shares | 450,000,000 | 450,000,000 |
Common Stock, shares issued | 195,055,724 | 195,055,724 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Revenues | ||||
Sales and other operating revenues | $ 1,809,575,000 | $ 2,787,116,000 | $ 5,288,933,000 | |
Gain on sale of assets | 1,663,000 | 154,155,000 | 138,903,000 | |
Interest and other income | 62,891,000 | 91,809,000 | 48,248,000 | |
Total revenues | 1,874,129,000 | 3,033,080,000 | 5,476,084,000 | |
Costs and Expenses | ||||
Lease operating expenses | 559,360,000 | 832,306,000 | 1,089,888,000 | |
Severance and ad valorem taxes | 43,826,000 | 65,794,000 | 107,215,000 | |
Exploration expenses, including undeveloped lease amortization | 101,861,000 | 470,924,000 | 513,600,000 | |
Selling and general expenses | 265,210,000 | 306,663,000 | 364,004,000 | |
Depreciation, depletion and amortization | 1,054,081,000 | 1,619,824,000 | 1,906,247,000 | |
Impairment of assets | 95,088,000 | 2,493,156,000 | 51,314,000 | |
Redetermination expense | [1] | 39,100,000 | ||
Accretion of asset retirement obligations | 46,742,000 | 48,665,000 | 50,778,000 | |
Deepwater rig contract exit costs | (4,344,000) | 282,001,000 | ||
Interest expense | 152,492,000 | 124,665,000 | 136,424,000 | |
Interest capitalized | (4,322,000) | (7,290,000) | (20,605,000) | |
Other expense | 18,150,000 | 78,634,000 | 24,949,000 | |
Total costs and expenses | 2,367,244,000 | 6,315,342,000 | 4,223,814,000 | |
Income (loss) from continuing operations before income taxes | (493,115,000) | (3,282,262,000) | 1,252,270,000 | |
Income tax expense (benefit) | (219,172,000) | (1,026,490,000) | 227,297,000 | |
Income (loss) from continuing operations | (273,943,000) | (2,255,772,000) | 1,024,973,000 | |
Loss from discontinued operations, net of income taxes | (2,027,000) | (15,061,000) | (119,362,000) | |
Net Income (Loss) | $ (275,970,000) | $ (2,270,833,000) | $ 905,611,000 | |
Per Common Share - Basic | ||||
Income (loss) from continuing operations | $ (1.59) | $ (12.94) | $ 5.73 | |
Loss from discontinued operations | (0.01) | (0.09) | (0.67) | |
Net income (loss) | (1.60) | (13.03) | 5.06 | |
Per Common Share - Diluted | ||||
Income (loss) from continuing operations | (1.59) | (12.94) | 5.69 | |
Loss from discontinued operations | (0.01) | (0.09) | (0.66) | |
Net income (loss) | $ (1.60) | $ (13.03) | $ 5.03 | |
Average Common shares outstanding - basic | 172,173,012 | 174,351,227 | 178,852,942 | |
Average Common shares outstanding - diluted | 172,173,012 | 174,351,227 | 180,070,984 | |
[1] | Results exclude corporate overhead, interest and discontinued operations. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract] | |||||
Net income (loss) | $ (275,970) | $ (2,270,833) | $ 905,611 | ||
Other comprehensive loss, net of tax | |||||
Net gain (loss) from foreign currency translation | 66,449 | (546,705) | (271,491) | ||
Retirement and postretirement benefit plans | 7,955 | 10,492 | (72,796) | ||
Deferred loss on interest rate hedges reclassified to interest expense | 1,926 | 1,926 | 1,913 | ||
Other comprehensive income (loss) | 76,330 | [1] | (534,287) | [1] | (342,374) |
Comprehensive income (loss) | $ (199,640) | $ (2,805,120) | $ 563,237 | ||
[1] | All amounts are presented net of income taxes. |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Operating Activities | ||||||
Net income (loss) | $ (275,970) | $ (2,270,833) | $ 905,611 | |||
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities: | ||||||
Loss from discontinued operations | 2,027 | 15,061 | 119,362 | |||
Depreciation, depletion and amortization | 1,054,081 | 1,619,824 | 1,906,247 | |||
Impairment of assets | 95,088 | 2,493,156 | 51,314 | |||
Amortization of deferred major repair costs | 3,794 | 7,296 | 8,345 | |||
Dry hole costs | 15,047 | 296,845 | 269,986 | |||
Amortization of undeveloped leases | 43,417 | 75,312 | 74,438 | |||
Accretion of asset retirement obligations | 46,742 | 48,665 | 50,778 | |||
Deferred income tax benefits | (387,843) | (978,030) | (170,915) | |||
Pretax gains from disposition of assets | (1,663) | (154,155) | (138,903) | |||
Net (increase) decrease in noncash operating working capital | (38,689) | 35,064 | (3,729) | |||
Other operating activities, net | 44,764 | (4,836) | (23,895) | |||
Net cash provided by continuing operations activities | 600,795 | 1,183,369 | 3,048,639 | |||
Investing Activities | ||||||
Property additions and dry hole costs | (926,948) | (2,549,736) | (3,679,464) | |||
Proceeds from sales of property, plant and equipment | 1,155,144 | 423,911 | 1,467,046 | |||
Purchase of investment securities | [1] | (695,879) | (911,787) | (986,328) | ||
Proceeds from maturity of investment securities | [1] | 761,000 | 1,129,139 | 899,857 | ||
Other investing activities, net | (7,230) | (13,648) | (18,929) | |||
Net cash provided (required) by investing activities | 286,087 | (1,922,121) | (2,317,818) | |||
Financing Activities | ||||||
Borrowings of debt | 541,444 | 600,000 | 100,000 | |||
Repayments of debt | (600,000) | (450,000) | ||||
Capital lease obligation payments | (10,447) | (10,434) | (25,265) | |||
Purchase of treasury stock | (250,000) | (375,000) | ||||
Issue cost of debt facility | (14,085) | |||||
Cash dividends paid | (206,635) | (244,998) | (236,371) | |||
Other financing activities, net | (1,158) | (9,129) | (8,074) | |||
Net cash required by financing activities | (290,881) | (364,561) | (544,710) | |||
Cash Flows from Discontinued Operations | ||||||
Operating activities | (15,005) | (39,563) | ||||
Investing activities | 5,314 | 199,541 | ||||
Changes in cash included in current assets held for sale | 192,585 | 100,790 | ||||
Net increase in cash and cash equivalents of discontinued operations | 182,894 | 260,768 | ||||
Effect of exchange rate changes on cash and cash equivalents | (6,387) | 10,294 | (3,726) | |||
Net increase (decrease) in cash and cash equivalents | 589,614 | (910,125) | 443,153 | |||
Cash and cash equivalents at January 1 | 283,183 | [2] | 1,193,308 | 750,155 | ||
Cash and cash equivalents at December 31 | $ 872,797 | $ 283,183 | [2] | $ 1,193,308 | ||
[1] | Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition. | |||||
[2] | Reclassified to conform to current presentation. See Note B for additional information. |
CONSOLIDATED STATEMENTS OF CAS7
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CONSOLIDATED STATEMENTS OF CASH FLOWS [Abstract] | |||
Maturity of Canadian government securities | 90 days | 90 days | 90 days |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands | Cumulative Preferred Stock [Member] | Common Stock [Member] | Capital In Excess Of Par Value [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] | Treasury Stock [Member] | Total | |
Balance at beginning of year at Dec. 31, 2013 | $ 194,920 | $ 902,633 | $ 8,058,792 | $ 172,119 | $ (732,734) | |||
Exercise of stock options, including income tax benefits | 120 | (11,422) | ||||||
Foreign currency translation gains (losses), net of income taxes | (271,491) | $ (271,491) | ||||||
Purchase of treasury shares | (375,000) | |||||||
Net income (loss) for the year | 905,611 | 905,611 | ||||||
Restricted stock transactions and other | (27,920) | |||||||
Cash dividends - $1.20 per share in 2016, $1.40 per share in 2015 and $1.325 per share in 2014 | (236,371) | |||||||
Retirement and postretirement benefit plans, net of income taxes | (72,796) | (72,796) | ||||||
Sale of stock under employee stock purchase plans | 420 | |||||||
Stock-based compensation | 43,490 | |||||||
Other | (40) | |||||||
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes | 1,913 | 1,913 | ||||||
Awarded restricted stock | 21,190 | |||||||
Balance at end of year at Dec. 31, 2014 | 195,040 | 906,741 | 8,728,032 | (170,255) | (1,086,124) | 8,573,434 | ||
Exercise of stock options, including income tax benefits | 16 | (376) | ||||||
Foreign currency translation gains (losses), net of income taxes | (546,705) | (546,705) | ||||||
Purchase of treasury shares | (250,000) | |||||||
Net income (loss) for the year | (2,270,833) | (2,270,833) | ||||||
Restricted stock transactions and other | (38,415) | |||||||
Cash dividends - $1.20 per share in 2016, $1.40 per share in 2015 and $1.325 per share in 2014 | (244,998) | |||||||
Retirement and postretirement benefit plans, net of income taxes | 10,492 | 10,492 | ||||||
Sale of stock under employee stock purchase plans | 491 | |||||||
Stock-based compensation | 42,322 | |||||||
Other | (198) | |||||||
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes | 1,926 | 1,926 | ||||||
Awarded restricted stock | 29,572 | |||||||
Balance at end of year at Dec. 31, 2015 | 195,056 | 910,074 | 6,212,201 | (704,542) | (1,306,061) | 5,306,728 | [1] | |
Exercise of stock options, including income tax benefits | (12,017) | |||||||
Foreign currency translation gains (losses), net of income taxes | 66,449 | 66,449 | ||||||
Net income (loss) for the year | (275,970) | (275,970) | ||||||
Restricted stock transactions and other | (10,078) | |||||||
Cash dividends - $1.20 per share in 2016, $1.40 per share in 2015 and $1.325 per share in 2014 | (206,635) | |||||||
Retirement and postretirement benefit plans, net of income taxes | 7,955 | 7,955 | ||||||
Sale of stock under employee stock purchase plans | 509 | |||||||
Stock-based compensation | 29,119 | |||||||
Other | (299) | |||||||
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes | 1,926 | 1,926 | ||||||
Awarded restricted stock | 8,992 | |||||||
Balance at end of year at Dec. 31, 2016 | $ 195,056 | $ 916,799 | $ 5,729,596 | $ (628,212) | $ (1,296,560) | $ 4,916,679 | ||
[1] | Reclassified to conform to current presentation. See Note B for additional information. |
CONSOLIDATED STATEMENTS OF STO9
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY [Abstract] | |||||
Cumulative Preferred Stock, par value (per share) | $ 100 | $ 100 | $ 100 | $ 100 | $ 100 |
Cumulative Preferred Stock, authorized shares | 400,000 | 400,000 | 400,000 | 400,000 | 400,000 |
Cumulative Preferred Stock, shares issued | 0 | 0 | 0 | 0 | 0 |
Common Stock, par value (per share) | $ 1 | $ 1 | $ 1 | $ 1 | $ 1 |
Common Stock, authorized shares | 450,000,000 | 450,000,000 | 450,000,000 | 450,000,000 | 450,000,000 |
Common Stock, shares issued | 195,055,724 | 195,055,724 | 195,055,724 | 195,055,724 | 195,040,149 |
Cash dividends, per share | $ 0.25 | $ 0.35 | $ 1.20 | $ 1.40 | $ 1.325 |
Treasury stock, shares | 22,853,547 | 23,021,013 | 22,853,547 | 23,021,013 | 17,540,636 |
Significant Accounting Policiei
Significant Accounting Policieis | 12 Months Ended |
Dec. 31, 2016 | |
Significant Accounting Policies [Abstract] | |
Significant Accounting Policies | Note A – Significant Accounting Policies NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and entered into an agreement to sale its Canadian heavy oil assets in December 2016. In addition, Murphy Oil sold its remaining downstream assets in the United Kingdom in 2015 and its U.K. retail marketing assets during 2014. See Note C regarding more information regarding the sale of these assets . PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated. REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2016 and 2015, the liabilities for natural gas balancing were immaterial. CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents. MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2016, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $111,542,000 . These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada. ACCOUNTS RECEIVABLE – At December 31, 2016 and 2015, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years. INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment. PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete. Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. During 2016 and 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2016, the Company recognized pretax noncash impairments charges of approximately $95,088,000 at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairments charges of $2,493,200,000 , to reduce the carrying value of certain producing properties in Malaysia, Western Canada and the Gulf of Mexico to their estimated fair value. See also Note E for further discussion of impairment charges. The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves; unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being depreciated on a straight-line basis over its estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in income (loss) as a separate component of revenues. Turnarounds for coking units at Syncrude Canada Ltd. were scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varied depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease operating expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. The Company sold its interest in Syncrude during 2016. Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, Plant and Equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs. GOODWILL – Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired. Goodwill is not amortized, but is assessed annually for recoverability of the carrying value. The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties with the carrying value of these net assets including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company recorded an impairment charge of $37,047,000 in 2014 and reduced the carrying amount to zero . ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. The Company does not provide U.S. deferred taxes for the portion of undistributed earnings of foreign subsidiaries when these earnings are considered indefinitely reinvested in the respective foreign operations. The unrecognized deferred tax liability is dependent on many factors including withholding taxes under current tax treaties, any repatriation occurring while the U.S. is in a taxable income position, and associated foreign tax credits. Under present law, the Company would incur a 5% withholding tax on any monies repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense. FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in other comprehensive loss until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in other comprehensive loss is recognized immediately in earnings. Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants . STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock prices. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three -year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the three-year vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards . PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Statement of Operations are recorded net of tax in Accumulated Other Comprehensive Loss. The remaining amounts in Accumulated Other Comprehensive Loss as of December 31, 2016 include net actuarial losses and prior service (cost) credit. NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share. USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates . |
New Accounting Principles and R
New Accounting Principles and Recent Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Principles and Recent Accounting Pronouncements [Abstract] | |
New Accounting Principles and Recent Accounting Pronouncements | Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principle Adopted Balance Sheet Classification of Deferred Taxes. In November 2015, the Financial Accounting Standards Board ( FASB) issued an Accounting Standards Update (ASU) that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The Company is required to adopt the ASU effective in the first quarter of 2017, but early adoption is permitted. The Company elected to adopt this ASU in 2016 using a retrospective approach. As a result of adoption, the Company reclassified $51.2 million for the year ended December 31, 2015, from current deferred income tax asset to long term deferred income tax asset , which is included in Deferred charges and other assets in the Consolidated Balance Sheets. Recent Accounting Pronouncements Revenue from Contracts with Customer s. In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method. The Company is performing an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings. Leases. In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements. Compensation-Stock Compensation . In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim period or annual period. The Company will adopt this guidance in 2017 which will not have a material impact on its consolidated financial statements and footnote disclosures. Statement of Cash Flows . In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statemen t of cash flows. The amendment provide s guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements. Business Combinations. In January 2017, the FASB issued an ASU to assist in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company will adopt this ASU beginning in 2018 and expects that the adoption of this ASU may have a material impact on future consolidated financial statements as goodwill would not be recorded for acquisitions that are not considered to be businesses. |
Discontinued Operations and Ass
Discontinued Operations and Assets Held for Sale | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Assets Held for Sale [Abstract] | |
Discontinued Operations and Assets Held for Sale | Note C – Discontinued Operations and Assets Held for Sale On September 30, 2014, the Company sold its U.K. retail marketing operations and associated inventories with total proceeds of $211,965,000 . The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in the second quarter of 2015 for cash proceeds of $5,500,000 . The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented. The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations and Seal operations in Canada reflected as held for sale on the Company’s C onsolidated B alance S heets at December 31, 201 6 and 201 5. ( Thousands of dollars ) 2016 2015 Current assets Cash $ 4,126 7,927 Accounts receivable 22,944 29,358 Other – 1,055 Total current assets held for sale $ 27,070 38,340 Current liabilities Accounts payable $ 270 2,433 Accrued compensation and severance – 2,179 Refinery decommissioning cost 2,506 2,685 Total current liabilities associated with assets held for sale $ 2,776 7,297 Non-current liabilities Asset retirement obligation – Seal asset $ 85,900 – Total non-current liabilities associated with assets held for sale $ 85,900 – The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which was sold in January 2017. The purchaser has assumed these abandonment obligations. See Note U for additional information. In 2014, the Company wrote down its net investment in the held for sale U.K. refining and marketing assets by $269,200,000 . The 2014 writedown was based on estimated salvage value of remaining refining and terminal assets as of the end of the year . The Company benefited in 2014 from a LIFO inventory liquidation credit of $209,600,000 and a gain on sale of the U.K. retail marketing assets of $101,700,000 . Th e s e charge s and benefits have been included in the results of discontinued operations. The results of operations associated with all discontinued operations are presented in the following table. ( Thousands of dollars ) 2016 2015 2014 Revenues $ – 381,747 2,786,394 Loss from operations before income taxes $ (2,027) (6,758) (261,873) Gain (loss) on sale before income taxes – (4,990) 101,684 Total loss from discontinued operations before taxes (2,027) (11,748) (160,189) Income tax expense (benefit) – 3,313 (40,827) Loss from discontinued operations $ (2,027) (15,061) (119,362) |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2016 | |
Inventories [Abstract] | |
Inventories | Note D – Inventories Inventories consisted of the following at December 31, 2016 and 2015. December 31, 2016 2015 ( Thousands of dollars ) Unsold crude oil $ 17,146 25,583 Materials and supplies 109,925 141,205 $ 127,071 166,788 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant And Equipment [Abstract] | |
Property, Plant and Equipment | Note E – Property, Plant and Equipment December 31, 2016 December 31, 2015 ( Thousands of dollars ) Cost Net Cost Net Exploration and production 1 $ 20,767,772 8,214,740 2 21,607,962 9,723,222 2 Corporate and other 156,231 101,448 134,596 95,143 $ 20,924,003 8,316,188 21,742,558 9,818,365 1 Includes mineral rights as follows: $ 595,138 188,689 1,075,040 612,518 2. Includes $48,053 in 2016 and $50,924 in 2015 related to administrative assets and support equipment. Divestments In 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”). The Company received net cash proceeds of $739,100,000 and re corded an after-tax gain of $71,700,000 in 2016 associated with the Syncrude divestiture. In 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received by Murphy upon clos ing of the transaction was $414,100,000 . A gain on sale of approximately $187,000,000 is being deferred and recognized over the next 20 years in the Canadian operating segment. The Company has amortized approximately $5,108,000 of the deferred gain during 2016. The remaining deferred gain is included as a component of deferred credits and other liabilities i n the Company’s Consolidated Balance Sheet s . In January 2015, the Company sold 10% of its oil and gas assets in Malaysia and received net cash proceeds of $417,200,000 . The Company recorded an after-tax gain of $218,800,000 in 2015 on the 10% sale . In December 2014, the Company sold 20% of its oil and gas assets in Malaysia and received net cash proceeds of $1,460,425,000 . The Company recorded an after-tax gain on this sale of $321,454,000 in 2014. Acquisition In 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which is unproved. Under the terms of the joint venture the total consideration amounts to approximately $375,000,000 of which Murphy paid $206,700,000 in cash at closing, subject to normal closing adjus tments, and the remaining $168,000,000 in the form of a carried interest on the Kaybob Duvernay property. The carry is to be paid over a period of up to five years. Impairments During 2016 and 2015 , declines in future oil and gas prices led to impairments in certain of the Company’s producing properties. During 2016, the Company recorded pretax noncash impairment charges of $95,088,000 to reduce the carrying values to their estimated fair values for Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash im pairment charges of $2,493,156,000 to reduce the carrying value of certain offshore producing and non-producing properties in the Gulf of Mexic o, producing offshore properties in Malaysia and for Western Canada onshore heavy oil producing properties . During 2014, the Company recorded an impairment writedown in the amount of $14,267,000 related to one gas well in the Gulf of Mexico. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. The following table reflects the recognized impairments for the three years ended December 31, 201 6 . December 31, ( Thousands of dollars ) 2016 2015 2014 Gulf of Mexico $ – 328,982 14,267 Canada 95,088 683,574 37,047 * Malaysia – 1,480,600 – $ 95,088 2,493,156 51,314 * This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. Other The Company had an 8.6% interest in the Kakap field in Block K Malaysia. The Kakap field in Block K is operated by another company and was jointly developed with the Gumusut field owned by others. In 2016 the Company recorded a $24 million after tax estimated redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. The Company expects to incur additional redetermination expense during 2017 for the period from the beginning of the year until the redetermination process is finalized, and the final adjustment will be settled in cash. In February 2017, PETRONAS officially approved the redetermination that reduces the Company’s working interest effective April 1, 2017. Exploratory Wells Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the C ompany is making sufficient progress assessing the reserves and the economic and operating viability of the project. At December 31, 201 6 , 201 5 and 201 4 , the Company had total capitalized drilling costs pending the determination of proved reserves of $148,500,000 , $130,514,000 and $120,455,000 , respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 201 6 . ( Thousands of dollars ) 2016 2015 2014 Beginning balance at January 1 $ 130,514 120,455 393,030 Additions to capitalized exploratory well costs pending the determination of proved reserves 17,986 64,578 2,874 Reclassifications to proved properties based on the determination of proved reserves – – (91,236) Reduction of capitalized exploratory well costs due to partial asset sale in Malaysia – – (122,175) Capitalized exploratory well costs charged to expense – (54,519) (62,038) Ending balance at December 31 $ 148,500 130,514 120,455 The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs has been capitalized . The projects are aged based on the last well drilled in the project. 2016 2015 2014 ( Thousands of dollars ) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Aging of capitalized well costs: Zero to one year $ 20,481 1 1 $ 66,032 7 6 $ – – – One to two years 63,527 5 5 – – – 59,330 3 1 Two to three years – – – 57,876 3 – 6,606 3 – Three years or more 64,492 6 – 6,606 3 – 54,519 2 2 $ 148,500 12 6 $ 130,514 13 6 $ 120,455 8 3 Of the $128,019,000 of e xploratory well costs capitalized more than one year at December 31, 201 6, $64,492,000 is in Brunei , and $63,527,000 is in Malaysia. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. The capitalized well costs charged to expense in 2015 included one well in the Gulf of Mexico in which development of the well could not be justified due to noncommercial hydrocarbon quantities found in the sidetrack and one project in the Gulf of Mexico deemed unlikely to be developed due to distressed commodity prices. The c apitalized well costs charged to expense in 2014 included four gas wells in Peninsula Malaysia and one well in the Gulf of Mexico. The Company’s application to extend the gas holding period for the Malaysia wells was denied by the Malaysian government in 2014. Development of the well in the Gulf of Mexico could not be justified due to the low prices for natural gas at year-end 2014, |
Financing Arrangements
Financing Arrangements | 12 Months Ended |
Dec. 31, 2016 | |
Financing Arrangements [Abstract] | |
Financing Arrangements | Note F – Financing Arrangements In August 2016, the Company entered into a new $1,200,000,000 senior unsecured guaranteed credit facility (“2016 facility”) with a major banking consortium. The 2016 facility expires in August 2019 . Facility fees of 0.5% are charged annually on the full 2016 facility commitment. The Company incurred transaction costs of approximately $14,000,000 to place the 2016 facility which are included in financing activities in the Consolidated Statement of Cash Flows. At December 31, 2016, the Company had no outstanding borrowings under the 2016 facility, however, there was approximately $88,000,000 of outstanding letters of credit under the 2016 facility. The 2016 facility is unsecured, with guarantees from certain domestic and foreign subsidiaries. Should the Company make substantial asset sales, the facility size would be automatically reduced to a minimum of $1,000,000,000 . Borrowings under the 2016 facility are subject to varying interest rates ranging from 250 to 450 basis points above LIBOR, with the borrowing rate currently at the high end of the range. The terms of the 2016 facility include certain financial covenants for the Company. These financial covenants include a minimum Adjusted EBITDAX (as defined in the 2016 facility) for the last twelve months (LTM) of 2.5 times LTM consolidated interest expense, consolidated debt not to exceed 3.75 times LTM Adjusted EBITDAX, and minimum liquidity from U.S. and Canadian entities equal to or greater than $500,000,000 . Also beginning March 31, 2017, if the Company’s total leverage ratio exceeds 3.25 times the Company’s LTM Adjusted EBITDAX, the facility will become secured, subject to limitations set forth in the Company’s existing notes. On December 21, 2016, the 2016 facility was amended. The amendment reduced the facility to $1,100,000,000 and removed the guarantee from Murphy Oil Company, Ltd (MOCL) conditional upon the Company meeting certain additional financial covenants. Should the Company exceed $500,000,000 of borrowings on the 2016 facility or consolidated debt exceeds 4.25 times LTM Adjusted EBITDAX excluding MOCL then the guarantee from MOCL would be re-instated. The covenant for consolidated debt as a multiple of LTM Adjusted EBITDAX excluding MOCL lowers to 4.0 times beginning September 30, 2017. At December 31, 2016, the Company was in compliance with all covenants related to both the 2016 facility and the 2011 facility. In August 2016, the Company reduced its existing $2,000,000,000 unsecured revolving credit facility (“2011 facility”) with a major banking consortium to $630,000,000 . Borrowings under this facility bear interest at 1.45% above LIBOR. The existing unsecured 2011 facility, which expires in June 2017 , includes a financial covenant under which the Company may not have total debt in excess of 60% of its total capital employed (debt borrowed plus stockholders’ equity). At December 31, 2016, the Company had no outstanding borrowings under the 2011 facility. In August 2016, the Company sold $550,000,000 of new notes that bear interest at the rate of 6.875% and mature on August 15, 2024 . The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment is to be made on February 15, 2017. The proceeds of the $550,000,000 notes were designated for general corporate purposes. The Company and its partners are parties to a 25 -year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15 -year period through 2029 . Current maturities and long-term debt on the Consolidated Balance Sheet included 20,617,000 and $195,785,000 , respectively, associated with this lease at December 31, 2016. |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Financing Arrangements [Abstract] | |
Long-term Debt | Note G – Long-term Debt December 31, (Thousands of dollars ) 2016 2015 Notes payable 2.50% notes, due December 2017 * $ 550,000 550,000 4.00% notes, due June 2022 500,000 500,000 3.70% notes, due December 2022 * 600,000 600,000 6.875% notes, due August 2024 550,000 - 7.05% notes, due May 2029 250,000 250,000 5.125% notes, due December 2042 * 350,000 350,000 Notes payable to banks, 1.4375% at December 31 - 600,000 Total notes payable 2,800,000 2,850,000 Unamortized discount on notes payable (23,835) (19,223) Total notes payable, net of unamortized discount 2,776,165 2,830,777 Capitalized lease obligation, due through March 2029 216,402 228,698 Total debt including current maturities 2,992,567 3,059,475 Current maturities (569,817) (18,881) Total long-term debt $ 2,422,750 3,040,594 * The interest rate paid is 1.0% above rate shown due to a downgrade of the credit rating for the Company’s no tes in February 2016. The amount of debt repayable over each of the next five years and thereafter are as follows: $569,817,000 in 2017, $13,554,000 in 2018, $14,233,000 in 2019, $14,988,000 in 2020, $15,697,000 in 2021 and $2,364,278,000 thereafter. . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | Note H – Asset Retirement Obligations The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 201 6 and 201 5 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment. A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 201 6 and 201 5 is shown in the following table. ( Thousands of dollars ) 2016 2015 Balance at beginning of year $ 825,312 875,728 Accretion expense 46,742 48,665 Liabilities incurred 13,690 76,775 Revisions of previous estimates (4,511) (85,504) Liabilities settled (20,589) (13,359) Liabilities assumed by purchaser of oil and gas assets (91,883) (33,448) Changes due to translation of foreign currencies 12,296 (43,545) Balance at end of year 781,057 825,312 Liabilities reported as held for sale at end of year 1 (85,900) – Current portion of liability at end of year 2 (13,629) (31,838) Noncurrent portion of liability at end of year $ 681,528 793,474 1 Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. 2 Included in Other Accrued Liabilities on the Consolidated Balance Sheet. The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
Income Taxes | Note I – Income Taxes The components of income (loss) from continuing operations before income taxes for each of the three years ended December 31, 201 6 and income tax expense (benefit) attributable thereto were as follows. ( Thousands of dollars ) 2016 2015 2014 Income (loss) from continuing operations before income taxes United States $ (595,196) (1,259,268) 179,484 Foreign 102,081 (2,022,994) 1,072,786 Total $ (493,115) (3,282,262) 1,252,270 Income tax expense (benefit) Federal – Current $ - (9,435) 25,151 – Deferred (197,450) (241,127) 25,444 (197,450) (250,562) 50,595 State 13,984 (5,294) 8,840 Foreign – Current 146,861 (40,550) 359,502 – Deferred (182,567) (730,084) (191,640) (35,706) (770,634) 167,862 Total $ (219,172) (1,026,490) 227,297 The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense. ( Thousands of dollars ) 2016 2015 2014 Income tax expense (benefit) based on the U.S. statutory tax rate $ (172,590) (1,148,792) 438,295 Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 8,582 49,739 20,562 State income taxes, net of federal benefit 9,090 (3,441) 5,746 U.S. tax benefit on certain foreign upstream investments (21,336) (16,939) (95,838) Current tax on distribution of foreign earnings – – 52,724 Deferred tax on distribution of foreign earnings – 188,461 – Tax effects on sale of Canadian assets (89,473) – – Tax effects on sale of Malaysian assets 2,080 (122,559) (227,241) Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures 25,734 40,788 37,712 Other, net 18,741 (13,747) (4,663) Total $ (219,172) (1,026,490) 227,297 In December 2015, one of the company’s foreign subsidiaries declared a $2,000,000,000 dividend payable to its parent. The dividend represented substantially all of the foreign subsidiary’s accumulated retained earnings under U.S. GAAP. The foreign subsidiary’s dividend was settled with an $800,000,000 cash payment plus issuance of a $1,200,000,000 note payable to its U.S. parent that was settled in June 2016. The dividend was completed without a U.S. current tax impact due to the utilization of the 2015 U.S. tax net operating loss combined with the shareholder’s ability to use allowed foreign tax credits that attached to the dividend. Based on the usage of the 2015 U.S. tax net operating loss, a noncash tax expense of $188,461,000 was recorded in 2015, primarily associated with using a U.S. deferred tax asset that would otherwise have carried forward to future years without the dividend. An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 201 6 and 201 5 showing the tax effects of significant temporary differences follows. ( Thousands of dollars ) 2016 2015 Deferred tax assets Property and leasehold costs $ 572,481 587,517 Liabilities for dismantlements 170,946 114,565 Postretirement and other employee benefits 214,288 226,217 Alternative minimum tax 29,710 39,683 Foreign tax credit carryforwards 33,295 855 U. S. net operating loss 454,231 – Other deferred tax assets 16,541 127,165 Total gross deferred tax assets 1,491,492 1,096,002 Less valuation allowance (305,389) (294,406) Net deferred tax assets 1,186,103 801,596 Deferred tax liabilities Accumulated depreciation, depletion and amortization (867,343) (793,972) Other deferred tax liabilities (21,908) (21,095) Total gross deferred tax liabilities (889,251) (815,067) Net deferred tax assets (liabilities) $ 296,852 (13,471) In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions and foreign tax credit carryforwards ; i n the judgment of management at the present time, these tax assets are not likely to be realized. The foreign tax credit carryforwards expire in 2017 through 2026 . The valuation allowance increased $10,983,000 in 2016 due to foreign tax carry forwards. S ubsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset. The Company has an estimated U.S. net operating loss of $1.29 billion at year-end 2016 with a corresponding deferred tax asset of $454,231,000 . The Company believes the U.S. net operating loss being carried forward will be utilized before it expires in 2036 . The Company has not recognized a deferred tax liability for undistr ibuted earnings of its Canadian and Malaysian operating subsidiaries because such earnings are considered indefinitely reinvested in foreign countries. As of December 31, 2016, undistributed earnings of the Company’s subsidiaries considered indefinitely r einvested were approximately $3.0 billion . The unrecognized deferred tax liability is dependent on many factors including withholding taxes under current tax treaties, any repatriation occurring while the United States is in a taxable income position, and associated foreign tax credits and the unrecognized deferred tax liability is estimated to be approximately $395,000,000 . Under present law, if the Company repatriates earnings from Canada to the United States in a future year, it would incur a 5% withholding tax on the amounts repatriated. Uncertain Income Tax Positions The FASB’s rules for accounting for i ncome tax uncertainties clarify the criteria for recognizing uncertain income tax benefits and require additional disclosures about uncertain tax positions. Under current rules the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon audit by the applicable taxing authority. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in Deferred c redits and o ther l iabilities in the Consolidated Balance Sheet s . A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years ended December 31, 201 6 is shown in the following table. ( Thousands of dollars ) 2016 2015 2014 Balance at January 1 $ 6,631 6,011 6,366 Additions for tax positions related to current year 756 821 988 Settlements due to lapse of time – – (1,225) Foreign currency translation effect 30 (201) (118) Balance at December 31 $ 7,417 6,631 6,011 All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded lia bilities as of December 31, 2016, 2015 and 2014 for interest and penalties of $343,000 , $233,000 and $142,000 , respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 201 6, 2015 and 2014 included net benefits for interest and penalties of $111,000 , $91,000 and $4,000 , respectively, associated with uncertain tax positions. During the next twelve months, the Company currently expects to add between $1,000,000 and $2,000,000 to the liabil ity for uncertain taxes for 2017 events. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2017 . The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled m atters. As of December 31, 2016 , the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2011 ; Canada – 2008 ; Malaysia – 2009 ; and United Kingdom – 2014 . |
Incentive Plans
Incentive Plans | 12 Months Ended |
Dec. 31, 2016 | |
Incentive Plans [Abstract] | |
Incentive Plans | Note J – Incentive Plans Murphy utilizes cash-based and/or share-based incentive plans to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the financial statements using a grant date fair value-based measurement method over the periods that the awards vest. For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award. At December 31, 2016, the Company has cash and incentive awards issued to employees under the 2012 Long-Term Incentive Plan (2012 Long-Term Plan) and the 2012 Annual Incentive Plan (2012 Annual Plan). The 2012 Annual Plan authorize s the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2012 Long-Term Plan authorize s the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2012 Long-Term Plan expires in 2022 . A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding; allowed shares not granted in an earlier year may be granted in future years. Based on awards made to date, approximately 3,000,000 shares remained available for grant under the 2012 Long-Term Plan at December 31, 201 6 . The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. Amounts recognized in the financial statements with respect to share-based plans are shown in the following table. ( Thousands of dollars ) 2016 2015 2014 Compensation charged against income (loss) before income tax benefit $ 46,300 44,021 53,157 Related income tax benefit recognized in income 15,244 13,583 15,604 As of December 31, 2016 , there were $28,458,000 in compensation costs to be expensed over approximately the next two years related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable statutory withholding taxes, upon each stock option exercise. Total income tax benefits realized from tax deductions related to stock option exercises under share- based payment arrangements were $36,000 and $5,364,000 for t he years ended December 31, 2015 and 2014 , respectively. There were no income tax benefits realized in 2016 due to no stock option exercises during the year. S hare- S ettled A wards STOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan and the 2007 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee . The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. 2016 2015 2014 Fair value per option grant $5.03 $10.97 – $11.08 $12.84 Assumptions Dividend yield 4.00% 2.40% – 2.50% 2.00% Expected volatility 45.00% 29.00% – 30.00% 29.00% Risk-free interest rate 1.32% 1.34% – 1.60% 1.62% Expected life 5.20 yrs. 5.30 yrs. 5.35 yrs. Changes in stock options outstanding during the last three years are presented in the following table. Number of Shares Average Exercise Price Outstanding at December 31, 2013 6,006,585 $ 56.80 Granted at FMV 772,900 55.82 Exercised (862,407) 49.27 Forfeited (314,828) 54.53 Outstanding at December 31, 2014 5,602,250 57.95 Granted at FMV 991,000 49.67 Exercised (32,349) 40.80 Forfeited (1,117,613) 31.99 Outstanding at December 31, 2015 5,443,288 52.93 Granted at FMV 862,000 17.57 Exercised – – Forfeited (547,853) 44.23 Outstanding at December 31, 2016 5,757,435 48.46 Exercisable at December 31, 2013 2,435,322 $ 51.79 Exercisable at December 31, 2014 3,030,105 53.10 Exercisable at December 31, 2015 3,542,352 52.26 Exercisable at December 31, 2016 3,830,535 53.80 Additional information about stock options outstanding at December 31, 201 6 is shown below. Options Outstanding Options Exercisable Range of Exercise Prices per Option No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value $17.57 to $39.02 892,350 5.9 $ 11,354,000 55,350 2.5 $ – $45.48 to $51.63 2,379,926 2.8 – 1,556,926 1.6 – $54.21 to $62.98 2,485,159 2.6 – 2,218,259 2.4 – 5,757,435 3.2 $ 11,354,000 3,830,535 2.0 $ – The total intrinsic value of options exercised during 2015 and 2014 was $221,000 and $12,003,000 , respectively. There were no options exercised in 2016 as all awards either had no intrinsic value or were not vested. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s Common stock. PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based r estricted stock units ( PRSUS ) to be settled in Common shares were granted in each of the last three years under the 2012 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PRSUS will not vest, but recognized compensation cost associated with the stock award would not be reversed. For past awards, the performance conditions were based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. During the performance period, PRSUS are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid or voting rights exist on awards of PRSUS prior to their settlement. Changes in PRSUS outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2016 2015 2014 Outstanding at beginning of year 1,103,986 1,397,040 1,560,292 Granted 394,000 455,000 464,300 Awarded (361,096) (521,800) (473,186) Forfeited (144,317) (226,254) (154,366) Outstanding at end of year 992,573 1,103,986 1,397,040 The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period. The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 201 6 , 201 5 and 201 4 are presented in the following table. 2016 2015 2014 Fair value per share at grant date $12.21 – $16.34 $44.03 – $48.12 $33.90 – $51.30 Assumptions Expected volatility 33.00% 26.00% 29.00% Risk-free interest rate 0.93% 0.85% 0.65% Stock beta 0.863 0.813 0.843 Expected life 3.0 yrs. 3.0 yrs. 3.0 yrs. TIME-LAPSE RESTRICTED STOCK UNITS – Time-lapsed r estricted stock units ( TRSUS ) have been granted to the Company’s Non-Employee Directors under the Directors Plan and, to certain employees under the 2012 Long-Term Plan. These awards vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $17.57 per share in 2016, $49.67 per share in 2015, and $55.20 to $60.85 per share in 201 4 . Changes in TRSUS outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2016 2015 2014 Outstanding at beginning of year 477,244 321,789 112,881 Granted 503,555 282,065 278,892 Vested and issued (32,092) (69,610) (54,884) Forfeited (25,425) (57,000) (15,100) Outstanding at end of year 923,282 477,244 321,789 EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company has an ESPP under which the Company’s Common stock can be purchased by eligible U.S. and Canadian employees. Each quarter, an eligible employee may elect to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. The ESPP will terminate on the earlier of the date that employees have purchased all 980,000 authorized shares or June 30, 2017. Employee stock purchases under the ESPP were 8,962 shares at an average price of $23.41 per share in 2016, 8,387 shares at an average price of $34.93 per share in 2015, and 6,739 shares at an average price of $56.22 per share in 2014. At December 31, 201 6 , 262,853 shares remained available for sale under the ESPP. Compensation costs related to the ESPP are estimated based on the value of the 10 % discount and the fair value of the option that provides for the refund of participant withholdings , and such expenses were $41,000 in 2016, $29,000 in 2015 and $55,000 in 2014. The fair value per share issued under the ESPP was approximately $2.94 , $5.74 and $6.49 for t he years ended December 31, 2016, 2015 and 2014 , respectively. C ash -S ettled A wards The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SAR), Performance-based restricted stock units (PRSUC), Time-based restricted stock units (TRSUC) and Phantom units. SAR awards have terms similar to stock options, PRSUC terms are similar to other performance-based restricted stock awards and TRSUC are generally settled on the third anniversary of the date of grant. Phantom units generally settle three to five years from date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares. Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $17,181,000 in 2016, $1,594,000 in 2015 and $9,667,000 in 2014. The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $25,800,000 , $26,393,000 and $38,000,000 was recorded in 201 6 , 201 5 and 201 4 , respectively, for these plans . |
Employee and Retiree Benefit Pl
Employee and Retiree Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Employee and Retiree Benefit Plans [Abstract] | |
Employee and Retiree Benefit Plans | Note K – Employee and Retiree Benefit Plans PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory. Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy. GAAP require s the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss . The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 201 6 and 201 5 and a statement of the funded status as of December 31, 201 6 and 201 5 . Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 794,589 825,552 115,222 118,496 Service cost 8,136 17,948 1,864 3,180 Interest cost 25,185 33,168 3,800 4,883 Plan amendments – 8,297 – – Participant contributions – 4 1,278 1,276 Actuarial loss (gain) 58,236 (48,019) (10,627) (7,436) Medicare Part D subsidy – – 510 510 Exchange rate changes (30,447) (15,337) 20 (112) Benefits paid (40,928) (35,936) (5,369) (5,575) Special termination benefits – 8,606 – – Curtailments 822 306 (19) – Obligation at December 31 815,593 794,589 106,679 115,222 Change in plan assets Fair value of plan assets at January 1 521,682 560,978 – – Actual return on plan assets 61,860 (18,718) – – Employer contributions 8,186 31,442 3,581 3,789 Participant contributions – 4 1,278 1,276 Medicare Part D subsidy – – 510 510 Exchange rate changes (30,609) (14,104) – – Benefits paid (40,928) (35,936) (5,369) (5,575) Other (834) (1,984) – – Fair value of plan assets at December 31 519,357 521,682 – – Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 7,591 7,463 – – Other accrued liabilities (8,184) (7,487) (5,267) (5,370) Deferred credits and other liabilities (295,643) (272,883) (101,412) (109,852) Funded status and net plan liability recognized at December 31 $ (296,236) (272,907) (106,679) (115,222) The significant actuarial loss in 2016 for pension benefits was primarily due to lower discount rate and lower fixed income yield rates, partially offset by lower assumed future salary increases. The significant actuarial gain in 2015 for pension benefits was primarily due to a combination of a higher discount rate and a reduction in assumed future salary increases. At December 31, 201 6 , amounts included in accumulated other comprehensive loss (AOC L ), before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table. ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits Net actuarial loss $ (247,622) (2,858) Prior service (cost) credit (6,831) 112 $ (254,453) (2,746) Amounts included in AOC L at December 31, 201 6 that are expected to be amortized into net periodic benefit expense during 201 7 are shown in the following table. ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits Net actuarial loss $ (14,257) – Prior service (cost) credit (1,019) 74 $ (15,276) 74 The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets. Projected Benefit Obligations Accumulated Benefit Obligations Fair Value of Plan Assets ( Thousands of dollars ) 2016 2015 2016 2015 2016 2015 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 643,174 630,587 599,730 622,841 497,894 500,695 Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets 156,088 148,019 150,780 140,544 – – Unfunded other postretirement plans 106,678 115,222 106,678 115,222 – – The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 201 6 . Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2014 2016 2015 2014 Service cost $ 8,136 17,948 22,470 1,864 3,180 2,459 Interest cost 25,185 33,168 33,680 3,800 4,883 4,617 Expected return on plan assets (28,154) (34,016) (33,723) – – – Amortization of prior service cost (credit) 1,204 1,560 899 (75) (82) (82) Amortization of transitional (asset) liability – (1) (480) – – – Recognized actuarial loss 16,165 15,147 9,471 5 992 5 22,536 33,806 32,317 5,594 8,973 6,999 Termination benefits expense – 8,606 – – – – Curtailment expense 822 306 – (19) – – Net periodic benefit expense $ 23,358 42,718 32,317 5,575 8,973 6,999 Termination and curtailment expenses in 2016 and 2015 were primarily related to plan amendments made upon early retirement of certain employees during 2016 and 2015. The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2016 2015 Benefit obligation at December 31 $ 206,502 197,549 615 643 Fair value of plan assets at December 31 197,575 193,933 – – Net plan liabilities recognized 8,927 3,616 615 643 Net periodic benefit expense (benefit) (2,244) 4,703 154 152 The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 201 6 and 201 5 and net periodic benefit expense for 201 6 and 201 5 . Benefit Obligations Net Periodic Benefit Expense Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31 December 31 Year Year 2016 2015 2016 2015 2016 2015 2016 2015 Discount rate 3.94% 4.37% 4.41% 4.61% 3.84% 4.04% 4.24% 4.12% Expected return on plan assets 5.62% 6.00% – – 5.62% 6.00% – – Rate of compensation increase 3.52% 3.74% – – 3.52% 3.74% – – T he discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company. Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table. ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits 2017 $ 38,532 6,161 2018 38,896 6,319 2019 39,833 6,435 2020 40,848 6,621 2021 41,653 6,824 2022-2026 221,350 36,326 For purposes of measuring postretirement benefit obligations at December 31, 201 6 , the future annual rates of increase in the cost of health care were assumed to be 7.2% for 201 7 decreasing each year to an ultimate rate of 4.5% in 202 8 and thereafter. Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects. ( Thousands of dollars ) 1% Increase 1% Decrease Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2016 $ 1,076 (818) Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2016 15,246 (12,251) During 201 6 , the Company made contributions of $7,499,000 to its domestic defined benefit pension plans, $687,000 to its foreign defined benefit pension plans, $3,554,000 to its domestic postretirement benefits plan and $28,000 to its foreign postretirement benefits plan. The Company currently expects during 201 7 to make contributions of $ 18,459,000 to its domestic defined benefit pension plans, $7,022,000 to its foreign defined benefit pension plans, $5,243,000 to its domestic postretirement benefits plan and $24,000 to its foreign postretirement benefits plan. Plan Investments – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee). Members of the Committee are appointed by the Chief Executive Officer of Murphy . The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement. The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities. The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation. The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities. The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans. The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70% ; fixed income securities of between 30% and 60% ; long/short equity of between 0% and 15% ; and cash and equivalents of between 0% and 15% . The Committee is authorized to direct investments within these parameters. Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds. Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term. Generally , no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100 million. Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets. Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity. The fixed income portfolio should not exceed an average maturity of 11 years. The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds. The Committee routinely reviews the investment performance of Investment Managers. For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees. The trustees have h ired a fiduciary investment manager to manage the assets of the plan within the parameters of the Statement of Investment Principles (Statement ). The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Statement while limiting the risk for the funded position of the plan. The Statement specifies a strategy with an allocation goal of 60% Delegated growth fund (DGF) equities and 40% Delegated liability fund (DLF). Also, the allocation goal includes interest rate hedge ratio and inflation rate hedge ratio of 100% . Hewitt Risk Management Services Limited (Manager) has discretion to vary the level of interest rate and inflation hedge ratios from the strategic levels. The DGF is diversified by style, strategy and asset class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies. The DLF aims to provide returns in line with the liabilities of typical pension schemes on an exposure basis in the relevant tenures and instruments (long/short, real/nominal). The DLF holds cash as collateral for the leveraged positions. Small working cash balances are permitted to facilitate daily management of payments and receipt s within the plan. The trustee routinely review the investment performance of the plan. For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets. A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio. The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash. The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation. The normal allocation includes total equity securities of 60% with a range of 40% to 75% of total assets. Fixed income securities have a normal allocation of 35% with a range of 25% to 45% . Cash will normally have an allocation of 5% with a range of 0% to 15% . The Policy calls for diversification norms within the investment portfolios of both equity securities and fixed income securities. The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 201 6 and 201 5 are presented in the following table. December 31, 2016 2015 Equity securities 58.4 % 64.4 % Fixed income securities 39.0 34.0 Cash equivalents 2.6 1.6 100.0 % 100.0 % The Company’s weighted average expected return on plan assets was 5.62% in 201 6 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 5.62% expected return was based on an expected average future equity securities return of 7.91% and a fixed income securities return of 4.21% and is net of average expected investment expenses of 0.60% . Over the last 10 years, the return on funded retirement plan assets has averaged 5.69% . At December 31, 201 6 , the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 61,554 61,554 – – U.S. small/midcap 23,103 23,103 – – Hedged funds and other alternative strategies 48,113 – 13,999 34,114 International commingled trust fund 67,451 – 67,451 – Emerging market commingled equity fund 16,006 – 16,006 – Fixed income securities: U.S. fixed income 78,473 – 78,473 – International commingled trust fund 13,486 – 13,486 – Emerging market mutual fund 5,775 – 5,775 – Cash and equivalents 7,821 7,821 – – Total Domestic Plans 321,782 92,478 195,190 34,114 Foreign Plans Equity securities funds 74,108 – 74,108 – Fixed income securities funds 97,075 – 97,075 – Diversified pooled fund 21,463 – 21,463 – Cash and equivalents 4,929 – 4,929 – Total Foreign Plans 197,575 – 197,575 – Total $ 519,357 92,478 392,765 34,114 At December 31, 201 5 , the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 51,878 51,878 – – U.S. small/midcap 26,964 26,964 – – Hedged funds and other alternative strategies 50,878 – 16,949 33,929 International commingled trust fund 72,205 – 72,205 – Emerging market commingled equity fund 16,873 – 16,873 – Fixed income securities: U.S. fixed income 80,681 – 80,681 – International commingled trust fund 15,332 – 15,332 – Emerging market mutual fund 6,439 – 6,439 – Cash and equivalents 6,499 6,499 – – Total Domestic Plans 327,749 85,341 208,479 33,929 Foreign Plans Equity securities funds 104,718 – 104,718 – Fixed income securities funds 67,494 – 67,494 – Diversified pooled fund 20,987 – 20,987 – Cash and equivalents 734 734 – – Total Foreign Plans 193,933 734 193,199 – Total $ 521,682 86,075 401,678 33,929 The definition of levels within the fair value hierarchy in the tables above is included in Note Q . For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market. Hedged funds and other alternative strategies funds consist of three investments. One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90 -day notice, and the third investment is also valued monthly based on net asset values and has a three year lock-up period and a 95 -day notice following the lock-up period . International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges. The emerging market commingled equity fund is valued monthly based on net asset value. These commingled equity funds can be withdrawn monthly and have a 10 -day notice period. U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values. International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values. The fixed income emerging market mutual fund is valued daily based on net asset value. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash. The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: ( Thousands of dollars ) Hedged Funds and Other Alternative Strategies Total at December 31, 2014 $ 33,952 Actual return on plan assets: Relating to assets held at the reporting date (23) Relating to assets sold during the period – Purchases, sales and settlements – Total at December 31, 2015 33,929 Actual return on plan assets: Relating to assets held at the reporting date 185 Relating to assets sold during the period – Purchases, sales and settlements – Total at December 31, 2016 $ 34,114 THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6% . Amounts charged to expense for these plans were $7,395,000 in 2016, $7,607,000 in 201 5 and $10,229,000 in 2014 . |
Financial Instruments and Risk
Financial Instruments and Risk Management | 12 Months Ended |
Dec. 31, 2016 | |
Financial Instruments and Risk Management [Abstract] | |
Financial Instruments and Risk Management | Note L – Financial Instruments and Risk Management DERIVATIVE INSTRUMENTS – Murphy uses derivative instruments to manage certain risks related to commodity prices, interest rates and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations . C ertain interest rate derivative contracts we re accounted for as hedges and the gain or loss associated with recording the fair value of these contracts w as deferred in Accumulated Other Comprehensive Loss until the anticipated transactions occur. Commodity Purchase Price Risks – The Company is subject to commodity price risk related to crude oil it produce s and sell s . During 2016, t he Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to economically hedge a portion of its United States production f or 2016 and 2017 . Under these contracts, which mature d monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At December 31, 2016, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017. At December 31, 201 6 , the fair value of WTI contracts of $48,900,000 was included in accounts payable. The impact of marking to market these 2017 commodity derivative contracts increased the loss before income taxes by $47,703,000 for the year ended December 31, 2016. During 2015, t he Company had WTI crude oil price swap financial contracts to hedge a portion of its United States production f or 2015 . At December 31, 2015, the Company had 20,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. At December 31, 2015, the fair value of WTI contracts of $89,400,000 was included in accounts receivable. The impact of marking to market these commodity derivative contracts reduced the loss before income taxes by $77,300,000 for the year ended December 31, 2015. Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At December 31, 201 6 and 201 5 , short-term derivative instruments were outstanding in Canada for approximately $14,200,000 and $4,800,000 , respectively, to manage the currency risk of U.S. dollar accounts receivable balance s associated with sale of Canadian crude oil in both years. The fair values of open foreign currency derivative contracts were liabilities of $73,000 at December 31, 2016 and $29,000 at December 31, 2015. At December 31, 201 6 and 201 5 , the fair value of derivative instruments not designated as hedging instruments are presented in the following table. December 31, 2016 December 31, 2015 Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives ( Thousands of dollars ) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Type of Derivative Contract Commodity – – Accounts Payable $48,864 Accounts Receivable $89,358 – – Foreign exchange – – Accounts Payable $73 – – Accounts Payable $29 For the years ended December 31, 201 6 and 201 5 , the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table. Year Ended December 31, 2016 Year Ended December 31, 2015 ( Thousands of dollars ) Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative Type of Derivative Contract Commodity Sale and Other Operating Revenues $ (63,412) Sale and Other Operating Revenues $ 129,064 Foreign exchange Interest and Other Income 26,714 Interest and Other Income (4) $ (36,698) $ 129,060 Interest Rate Risks – In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350,000,000 of notes that were sold in 2012. These interest rate swaps matured in May 2012. Under hedge accounting rules, the Company deferred a loss on these contracts to match the payment of interest on these notes through 2022. During each of the three years ended December 31, 2016, $2,963,000 of the deferred loss on the interest rate swaps was charged to interest expense in the Consolidated Statements of Operations. The remaining loss deferred on these matured contracts at December 31, 2016 was $15,926,000 , which is recorded, net of income taxes of $5,574,000 , in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheets. The Company expects to charge approximately $2,963,000 of this deferred loss to Interest expense in the Consolidated Statements of Operations during 201 7 . CREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S., Canada and Malaysia, and cost sharing amounts of operating and capital costs billed to partners for oil and natural gas fields operated by Murphy . The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level. Cash equivalents are placed with several major financial institutions, which limit the Company’s exposure to credit risk. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | |
Stockholders' Equity | Note M – Stockholders’ Equity During 2015 and 2014, the Company repurchased Common Stock under variable term, capped accelerated share repurchase transactions (ASR) as authorized by the Board of Directors. These share repurchases during 2015 and 2014 were as follows: 2015 2014 Purchase of Treasury Stock $ 250,000,000 $ 375,000,000 Shares repurchased 5,967,313 6,373,718 There were no share repurchases during 2016 and no open share buyback programs as of December 31, 2016. The shares acquired under the various buyback programs are carried as Treasury Stock in the Consolidated Balance Sheet s . |
Earnings per Share
Earnings per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings per Share [Abstract] | |
Earnings per Share | Note N – Earnings per Share Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the thr ee years ended December 31, 2016 . The following table reconciles the weighted-average shares outstanding used for these computations. ( Weighted-average shares ) 2016 2015 2014 Basic method 172,173,012 174,351,227 178,852,942 Dilutive stock options and restricted stock units * – – 1,218,042 Diluted method 172,173,012 174,351,227 180,070,984 * Due to a net loss recognized by the Company for the year ended December 31, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive. The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 201 6 , but were not included in the computation of dilut ive earnings per share because the incremental shares from the assumed conversion were antidilutive. 2016 2015 2014 Antidilutive stock options excluded from diluted shares 5,757,435 5,443,288 1,893,364 Weighted average price of these options $48.46 $52.93 $55.21 |
Other Financial Information
Other Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Other Financial Information [Abstract] | |
Other Financial Information | Note O – Other Financial Information DEEPWATER RIG CONTRACT EXIT COSTS – At year-end 2015, the Company had two deepwater drilling rigs in the Gulf of Mexico under contract that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The Company reported a pretax charge to earnings in 2015 totaling $282,001,000 that included both the costs incurred in 2015 during which the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016. The contract originally scheduled to expire in November 2016 was terminated by the Company. The Company paid approximately $266,700,000 related to these contracts in 2016 and reported a pretax benefit to earnings in 2016 totaling $4,330,000 for the final settlement of the contracts at less than the recorded costs. GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $59,731,000 in 2016 , $87,961,000 in 201 5 and $40,596,000 in 201 4 . Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2016 as shown in the following table. ( Thousands of dollars ) 2016 2015 2014 Accounts receivable $ 119,671 297,625 175,820 Inventories (5,171) (15,340) 25,697 Prepaid expenses 149,946 (144,845) 6,575 Deferred income tax assets - 3,924 6,884 Accounts payable and accrued liabilities (328,078) (36,887) (54,785) Current income tax liabilities 24,943 (69,413) (163,920) Net (increase) decrease in noncash operating working capital $ (38,689) 35,064 (3,729) Supplementary disclosures (including discontinued operations): Cash income taxes paid, net of refunds $ 6,707 118,667 573,799 Interest paid, net of amounts capitalized 127,798 110,386 114,232 Noncash investing activities, related to continuing operations: Asset retirement costs capitalized $ 13,690 76,775 70,568 Decrease in capital expenditure accrual 158,885 462,474 93,080 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Loss | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Loss [Abstract] | |
Accumulated Other Comprehensive Loss | Note P – Accumulated Other Comprehensive Loss The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 201 6 and December 31, 201 5 and the changes during 2016 and 201 5 are presented net of taxes in the following table. ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) 1 Retirement and Postretirement Benefit Plan Adjustments 1 Deferred Loss on Interest Rate Derivative Hedges 1 Total 1 Balance at December 31, 2014 $ 33,701 (189,752) (14,204) (170,255) 2015 components of other comprehensive income (loss): Before reclassifications to income (588,450) (5,468) – (593,918) Reclassifications to income 41,745 2 15,960 3 1,926 4 59,631 Net other comprehensive income (loss) (546,705) 10,492 1,926 (534,287) Balance at December 31, 2015 (513,004) (179,260) (12,278) (704,542) 2016 components of other comprehensive income (loss): Before reclassifications to income 66,449 (3,763) – 62,686 Reclassifications to income – 11,718 3 1,926 4 13,644 Net other comprehensive income 66,449 7,955 1,926 76,330 Balance at December 31, 2016 $ (446,555) (171,305) (10,352) (628,212) 1 All amounts are presented net of income taxes. 2 Reclassification for the year ended December 31, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K. 3 Reclassifications before taxes of $21,721 and $18,036 are included in the computation of net periodic benefit expense in 2015 and 2016 , respectively. See Note K for additional information. Related income taxes of $5,761 and $6,318 are included in income tax expense in 2015 and 2016 , respectively. 4 Reclassifications before taxes of $2,963 are included in Interest expense in both 2015 and 2016 . Related income taxes of $1,037 are includ ed in income tax expense in 2015 and 2016 . See Note L for additional information. |
Assets and Liabilities Measured
Assets and Liabilities Measured at Fair Value | 12 Months Ended |
Dec. 31, 2016 | |
Assets and Liabilities Measured at Fair Value [Abstract] | |
Assets and Liabilities Measured at Fair Value | Note Q – Assets and Liabilities Measured at Fair Value Fair Values – Recurring The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. The fair value measurements for these assets and liabilities at December 31, 201 6 and 2015 are presented in the following table. December 31, 2016 December 31, 2015 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity derivative contracts – – – – – 89,358 – 89,358 $ – – – – – 89,358 – 89,358 Liabilities: Nonqualified employee savings plans $ 13,904 – – 13,904 12,971 – – 12,971 Commodity derivative contracts – 48,864 – 48,864 – – – – Foreign currency exchange derivative contracts – 73 – 73 – 29 – 29 $ 13,904 48,937 – 62,841 12,971 29 – 13,000 The fair value of West Texas Intermediate (WTI) crude oil contracts in 2016 and 2015 was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of crude oil derivative contracts is recorded in Sales and o ther o perating r evenues in the Consolidated Statements of Operations , while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and o ther income. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses. The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at December 31, 2016 and 201 5. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 201 6 and 201 5 . The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The carrying value of Canadian government securities is determined based on cost plus earned interest. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. The Company has off-balance sheet exposures relating to c ertain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal. At December 31, 2016 2015 ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value Financial assets (liabilities): Canadian government securities with maturities greater than 90 days at the date of acquisition $ 111,542 111,331 173,288 173,234 Current and long-term debt (2,992,567) (2,951,992) (3,059,475) (2,189,858) Fair Values – Nonrecurring As a result of significantly lower commodity prices during 2016 and 2015, the Company recognized approximately $95,088,000 and $2,493,156,000, respectively, in pretax noncash impairment charges related primarily to producing properties. The fair value information associated with these impaired properties is presented in the following table. Year Ended December 31, 2016 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense Assets: Impaired proved properties Canada – – 71,967 167,055 95,088 $ – – 71,967 167,055 95,088 Year Ended December 31, 2015 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense Assets: Impaired proved properties Gulf of Mexico $ – – 316,106 645,088 328,982 Western Canada – – 23,526 707,100 683,574 Malaysia – – 1,200,900 2,681,500 1,480,600 $ – – 1,540,532 4,033,688 2,493,156 The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2016 | |
Commitments [Abstract] | |
Commitments | Note R – Commitments The Company leases production and other facilities under operating leases. The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field and a production facilit y at the West Patricia field. During each of the next five years, expected future net rental payments under all operating leases are approximately $71,335,000 in 201 7 , $67,586,000 in 2018 , $54,672,000 in 2019, $54,423,000 in 2020 and $54,622,000 in 2021 . Rental expense for noncancellable operating leases, including contingent payments when applicable, was $77,520,000 in 2016, $111,425,000 in 2015, and $144,981,000 in 201 4 . A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note G . The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 201 6 . These rigs will primarily be utilized for drilling ope rations onshore U.S. and Canada and offshore Malaysia. Future commitments under these contracts, all of which expire by 201 9 , total $45,042,000 . A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods. The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada. The U.S. transportation contracts require minimum monthly payments through 202 4, while the Western Canada processing contracts call for minimum monthly payments through 2035 . Future required minimum monthly payments for the next five years are $53,893,000 in 201 7 , $48,962,000 in 201 8, $42,616,000 in 201 9, $46,597,000 in 2020 and $47,793,000 in 2021 . Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total c osts incurred under these service arrangements were $50,300,000 in 2016, 32,473,000 in 2015, and $34,597,000 in 201 4 . Commitments for capital expenditures were approximately $585,651,000 at December 31, 201 6 , including $224,485,000 for field development and future work commitments in Malaysia, $156,984,000 for development at Kaybob Duvernay in Canada, $107,002,000 for work in the Eagle Ford Shale, $25,202,000 for costs to develop deepwater Gulf of Mexico fields, and $27,178,000 and $12,828,000 for future work commitments in Vietnam and Brunei , respectively. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Contingencies [Abstract] | |
Environmental and Other Contingencies | Note S – Contingencies The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases , tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company. ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws , the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income , financial condition or liquidity in a future period. In early 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified. The Company has not yet established a complete estimate of the costs to remediate the site. Based on the assessments done to date, the Company recorded $43.9 million in Other expense in the 2015 Consolidated Statements of Operations associated with the estimated costs of remediating the site. The Company has spent $35.3 million from inception to the end of 2016. Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of liability recorded. There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income , cash flows or liquidity. LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income , financial condition or liquidity in a future period. |
Common Stock Issued and Outstan
Common Stock Issued and Outstanding | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | |
Common Stock Issued and Outstanding | Note T – Common Stock Issued and Outstanding Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 201 6 is shown below. ( Number of shares outstanding ) 2016 2015 2014 At beginning of year 172,034,711 177,499,513 183,406,513 Stock options exercised* - 15,575 119,994 Restricted stock awards* 158,504 478,549 339,985 Employee stock purchase and thrift plans 8,962 8,387 6,739 Treasury shares purchased - (5,967,313) (6,373,718) At end of year 172,202,177 172,034,711 177,499,513 * Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares . |
Subsequent Event
Subsequent Event | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Event [Abstract] | |
Subsequent Event | Note U – Subsequent Events In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million. A $132.4 million pretax gain is expected to be reported in the first quarter of 2017 related to the sale. |
Business Segments
Business Segments | 12 Months Ended |
Dec. 31, 2016 | |
Business Segments [Abstract] | |
Business Segments | Note V – Business Segments Murphy’s reportable segments are organized into geographic areas of operations. The Company’s exploration and production activity is subdivided into segments for the United States, Canada, Malaysia and all other countries. Each of these segments derives revenues primarily from the sale of crude oil , condensate, natural gas liquids and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. Intersegment transfers of crude oil, natural gas and petroleum products are at market prices and intersegment services are recorded at cost. The Company completed the sale of its U.K. downstream assets during 2015 . The Company sold its retail marketing operations in the United Kingdom on September 30, 2014. For all years presented , assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the C onsolidated Balance S heet s . These operations have been reported as discontinued operations for all periods presented in these consolidated financial statements. The Company has several customers that purchase a significant portion of its oil and natural gas production. During 2016, sales to Phillips 66 and affiliated companies represented approximately 17% of the Company’s total sales revenue. During 2015, sales to Phillips 66 and affiliated companies represented approximately 17% of the Company’s total sales revenue. During 2014, sales to Shell Oil and affiliated companies and Phillips 66 and affiliated companies represented approximately 20% and 14% , respectively, of the Company’s total sales revenue. Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices. Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate and other activities, including interest income , miscellaneous gains and losses, interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the table on the following page, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets , and goodwill and other intangible assets. Segment Information Exploration and Production ( Millions of dollars ) United States Canada Malaysia Other Total E&P Year ended December 31, 2016 Segment loss $ (205.4) (35.9) 171.1 (54.7) (124.9) Revenues from external customers 685.7 365.3 753.4 0.2 1,804.6 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) (87.9) (134.3) 85.9 (18.8) (155.1) Significant noncash charges (credits) Depreciation, depletion and amortization 600.5 203.2 227.7 5.9 1,037.3 Accretion of asset retirement obligations 17.1 13.3 16.3 – 46.7 Amortization of undeveloped leases 38.4 4.5 – 0.5 43.4 Impairment of assets – 95.1 – – 95.1 Deferred and noncurrent income taxes (108.4) (175.8) (8.5) (18.3) (311.0) Additions to property, plant, equipment 269.8 361.3 101.4 (1.3) 731.2 Total assets at year-end 5,419.0 1,559.5 2,024.7 115.7 9,118.9 Year ended December 31, 2015 Segment loss $ (615.7) (583.4) (653.2) (158.6) (2,010.9) Revenues from external customers 1,253.6 549.7 1,131.4 – 2,934.7 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax benefit (337.0) (188.8) (567.9) (17.3) (1,111.0) Significant noncash charges (credits) Depreciation, depletion and amortization 794.9 261.9 544.9 6.2 1,607.9 Accretion of asset retirement obligations 20.2 12.6 15.9 – 48.7 Amortization of undeveloped leases 59.2 14.4 – 1.8 75.4 Impairment of assets 329.0 683.6 1,480.6 – 2,493.2 Deferred and noncurrent income taxes (187.7) (146.0) (579.2) (4.6) (917.5) Additions to property, plant, equipment 1,263.1 184.9 244.4 39.2 1,731.6 Total assets at year-end 5,717.8 2,460.6 2,537.2 147.7 10,863.3 Year ended December 31, 2014 Segment income (loss) $ 387.1 156.5 896.2 (250.0) 1,189.8 Revenues from external customers 2,196.4 1,044.1 2,183.5 (1.3) 5,422.7 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) 214.8 64.2 102.6 (95.9) 285.7 Significant noncash charges (credits) Depreciation, depletion and amortization 840.7 316.7 735.0 5.1 1,897.5 Accretion of asset retirement obligations 17.5 15.2 18.1 – 50.8 Amortization of undeveloped leases 50.1 19.4 – 4.9 74.4 Impairment of assets 14.3 37.0 – – 51.3 Deferred and noncurrent income taxes 39.7 43.3 (235.1) – (152.1) Additions to property, plant, equipment 2,028.7 445.9 818.0 10.7 3,303.3 Total assets at year-end 5,745.7 3,769.8 4,887.1 138.7 14,541.3 Geographic Information Certain Long-Lived Assets at December 31 ( Millions of dollars ) United States Canada Malaysia United Kingdom Other Total 2016 $ 5,121.6 1,451.4 1,637.0 – 106.2 8,316.2 2015 5,484.7 2,310.6 1,912.0 – 111.1 9,818.4 2014 5,419.5 3,574.6 4,258.8 0.4 78.1 13,331.4 Segment Information — Continued ( Millions of dollars ) Corporate and Other Discontinued Operations Consolidated Total Year ended December 31, 2016 Segment loss $ (149.1) (2.0) (276.0) Revenues from external customers 69.5 – 1,874.1 Interest income 2.9 – 2.9 Interest expense, net of capitalization 148.2 – 148.2 Income tax expense (benefit) (64.1) – (219.2) Significant noncash charges (credits) Depreciation, depletion and amortization 16.8 – 1,054.1 Accretion of asset retirement obligations – – 46.7 Amortization of undeveloped leases – – 43.4 Impairment of assets – – 95.1 Deferred and noncurrent income taxes (76.8) – (387.8) Additions to property, plant, equipment 21.9 – 753.1 Total assets at year-end 1,149.9 27.1 10,295.9 Year ended December 31, 2015 Segment loss $ (244.9) (15.0) (2,270.8) Revenues from external customers 98.4 – 3,033.1 Interest income 4.0 – 4.0 Interest expense, net of capitalization 117.4 – 117.4 Income tax expense (benefit) 84.5 – (1,026.5) Significant noncash charges (credits) Depreciation, depletion and amortization 11.9 – 1,619.8 Accretion of asset retirement obligations – – 48.7 Amortization of undeveloped leases – – 75.4 Impairment of assets – – 2,493.2 Deferred and noncurrent income taxes (60.5) – (978.0) Additions to property, plant, equipment 59.9 – 1,791.5 Total assets at year-end 592.2 38.3 11,493.8 Year ended December 31, 2014 Segment income (loss) $ (164.8) (119.4) 905.6 Interest income 7.7 – 7.7 Interest expense, net of capitalization 115.8 – 115.8 Income tax expense (benefit) (58.4) – 227.3 Significant noncash charges (credits) Depreciation, depletion and amortization 8.7 – 1,906.2 Accretion of asset retirement obligations – – 50.8 Amortization of undeveloped leases – – 74.4 Impairment of assets – – 51.3 Deferred and noncurrent income taxes (18.8) – (170.9) Additions to property, plant, equipment 14.5 – 3,317.8 Total assets at year-end 1,773.9 427.1 16,742.3 Geographic Information Revenues from External Customers for the Year ( Millions of dollars ) United States Canada Malaysia Other Total 2016 $ 693.2 421.1 759.3 0.5 1,874.1 2015 1,260.0 557.3 1,210.9 4.9 3,033.1 2014 2,201.5 1,052.4 2,233.0 (10.8) 5,476.1 |
Supplemental Oil and Gas Inform
Supplemental Oil and Gas Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Oil and Gas Information [Abstract] | |
Supplemental Oil and Gas Information | The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning f ive of the schedules. SCHEDULE 1 – SUMMARY OF PROVED CRUDE OIL AND SYNTHETIC OIL RESERVES SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS RESERVES Reserves of crude oil, synthetic oil, condensate , natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic produc t ibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analogue based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available. Prior to its disposition in 2016, Murphy included synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. This operation involves a process of mining tar sands and converting the raw bitumen into a pipeline-quality crude. The proved reserves associated with this project are estimated through a combination of core-hole drilling and realized process efficiencies. The high-density core-hole drilling, at a spacing of less than 500 meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content. The bitumen generally constitutes approximately 10 % of the tota l bulk tar sand that is mined. The bitumen extraction process is fairly efficient and removes about 90 % of the bitumen that is contained within the tar sand. The final step of the process converts the 8.4° API bitumen into 30°-34° API crude oil. A catalytic cracking process is used to crack the long hydrocarbon chains into shorter ones yielding a final crude oil that can be shipped via pipelines. The cracking process has an efficiency ranging from 85 % to 90 %. Overall, it takes approximately two metric tons of oil sand to produce one barrel of synthetic crude oil. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product. Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids . All crude oil and synthetic reserves, natural gas liquids reserves and natural gas reserves are from consolidated subsidiaries and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method. All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. Liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 66.2 million barrels and 539.8 billion cubic feet, respectively, at December 31, 2016. Approximately 26.5 billion cubic feet of natural gas proved reserves in Malaysia at December 31, 2016 relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $ 0.24 per thousand cubic feet. SCHEDULE 5 – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES Results of operations from exploration and production activities by geographic area for 2014 are reported as if these activities were not part of an operation that also refines crude oil and sells refined products. SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES GAAP require s calculation of future net cash flows using a 10 % annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 201 6 . Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices for 201 3 – 201 6 Crude & Synthetic Oil Crude Oil Synthetic Oil ( Millions of barrels ) Total Total United States Canada Malaysia Canada Proved developed and undeveloped crude oil / synthetic oil reserves: December 31, 2013 471.2 354.2 191.5 38.7 124.0 117.0 Revisions of previous estimates (9.3) (2.3) (3.2) 2.7 (1.8) (7.0) Improved recovery 7.5 7.5 – – 7.5 – Extensions and discoveries 42.6 42.6 32.7 2.4 7.5 – Purchases of properties 6.1 6.1 6.1 – – – Sales of properties (24.3) (24.3) (0.3) (0.5) (23.5) – Production (52.0) (47.6) (21.9) (5.9) (19.8) (4.4) December 31, 2014 441.8 336.2 204.9 37.4 93.9 105.6 Revisions of previous estimates 5.3 (8.2) (7.6) (4.8) 4.2 13.5 Improved recovery 2.4 2.4 – – 2.4 – Extensions and discoveries 63.8 63.8 63.8 – – – Sales of properties (11.0) (11.0) – – (11.0) – Production (46.1) (41.8) (22.2) (4.7) (14.9) (4.3) December 31, 2015 456.2 341.4 238.9 27.9 74.6 114.8 Revisions of previous estimates (5.8) (5.8) (10.9) 2.5 2.6 – Extensions and discoveries 11.0 11.0 8.6 – 2.4 – Purchases of properties 26.3 26.3 – 26.3 – – Sales of properties (121.0) (7.8) (4.5) (3.3) – (113.2) Production (37.7) (36.1) (17.7) (4.5) (13.9) (1.6) December 31, 2016 329.0 329.0 214.4 48.9 65.7 – Proved developed crude oil / synthetic oil reserves: December 31, 2013 289.9 172.9 75.8 31.6 65.5 117.0 December 31, 2014 324.1 218.5 106.2 32.4 79.9 105.6 December 31, 2015 326.6 211.8 125.9 23.8 62.1 114.8 December 31, 2016 184.9 184.9 113.9 19.2 51.8 – Proved undeveloped crude oil / synthetic oil reserves: December 31, 2013 181.3 181.3 115.7 7.1 58.5 – December 31, 2014 117.7 117.7 98.7 5.0 14.0 – December 31, 2015 129.6 129.6 113.0 4.1 12.5 – December 31, 2016 144.1 144.1 100.5 29.7 13.9 – Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices for 201 3 – 201 6 – Continued 201 6 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes Revision s of previous estimate – The 2016 negative crude oil revision in the U.S. was primarily attributable to impacts of lower pr ice on Eagle Ford Shale volumes and reduced performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the Gulf of Mexico. The positive Canadian oil reserves revision s in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling. The positive revision s for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis. Extensions and discoveries – In 2016, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and deeper oil-water contacts realized at a field in Malaysia. Purchases of Properties – In 2016, the Company’s Canadian subsidiary acquired working interests in the Kaybob Duvernay and liquids rich Placid Montney areas. The crude oil reserves are all associated with the Kaybob Duvernay area. Sales of properties – In the U.S., proved oil reserves were re duced following the sale of certain non-core Eagle Ford Shale acreage. In Canada, the Company sold its interests in b oth a heavy oil field and a synthetic oil project. 2015 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes Revisions of previous estimate – The 2015 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes, partially offset by improved Eagle Ford Shale performance, improved Eagle Ford Shale lifting costs, and drilling activity in the Gulf of Mexico. The negative Canadian conventional oil reserves revision in 2015 was result of lower heavy oil prices partially offset by increases at both Hibernia and Terra Nova due to development drilling and lower government royalty effects. The positive synthetic oil revision in the current period is due predominantly to lower government royalty effects due to lower oil prices. The positive revision for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices. Improved recovery – The 2015 Malaysia crude oil proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields. Extensions and discoveries – In 2015, the U.S. added proved oil reserves primarily for planned drilling activities in the Eagle Ford Shale. Sales of properties – The proved crude oil reserves reduction in Malaysia was associated with the 2015 sale of 10% of the Company’s oil and gas assets. Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices for 201 3 – 201 6 – Continued 201 4 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes Revisions of previous estimates – The 2014 negative crude oil revision in the U.S. was primarily attributed to a new downspacing drilling strategy at the Eagle Ford Shale, which recognizes incrementally greater reserves as an Extension for 2014. The positive Canadian conventional oil reserves revision in 2014 was based on Hibernia well performance and stronger heavy oil prices during 2014. The negative synthetic oil revision in 2014 was based on a review of the recoverable bitumen area coupled with the impact of a lower oil price. The negative revision for crude oil reserves in Malaysia in 2014 was attributable to an updated decline curve analysis for the Kikeh field, partially offset by a benefit for performance associated with field ramp up at Kakap. Improved recovery – This 2014 Malaysia crude oil proved reserves adds were associated with favorable impacts for waterflood activities at the Kikeh, Siakap North and Sarawak oil fields. Extensions and discoveries – In 2014, the U.S. added proved oil reserves primarily for substantial drilling activities in the Eagle Ford Shale. Canadian proved oil reserves adds in 2014 were associated with drilling activities in the Seal heavy oil area and at the Hibernia field. The crude oil proved reserves adds in 2014 in Malaysia were mostly for drilling activities at the Siakap North and Sarawak oil fields. Purchases of properties – The proved crude oil reserves adds in the U.S. were due to acquisition of an interest in the Kodiak field in the Gulf of Mexico. Sales of properties – The proved crude oil reserves reduction in Malaysia was associated with the late 2014 sale of 20% of the Company’s oil and gas assets. Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on A verage Prices for 201 3 – 201 6 ( Millions of barrels ) Total United States Canada Malaysia Proved developed and undeveloped NGL reserves: December 31, 2013 24.4 23.2 0.1 1.1 Revisions of previous estimates 5.1 5.0 – 0.1 Extensions and discoveries 4.7 4.0 0.6 0.1 Sales of properties (0.2) – – (0.2) Production (3.4) (3.1) – (0.3) December 31, 2014 30.6 29.1 0.7 0.8 Revisions of previous estimates 2.0 2.2 (0.3) 0.1 Extensions and discoveries 7.6 7.6 – – Sales of properties (0.1) – – (0.1) Production (3.7) (3.5) – (0.2) December 31, 2015 36.4 35.4 0.4 0.6 Revisions of previous estimates 1.6 1.2 0.2 0.2 Extensions and discoveries 2.9 2.8 0.1 – Purchases of properties 5.1 – 5.1 – Production (3.5) (3.0) (0.2) (0.3) December 31, 2016 42.5 36.4 5.6 0.5 Proved developed NGL reserves: December 31, 2013 14.2 13.1 – 1.1 December 31, 2014 17.5 16.5 0.2 0.8 December 31, 2015 21.6 20.7 0.3 0.6 December 31, 2016 22.2 20.8 0.9 0.5 Proved undeveloped NGL reserves: December 31, 2013 10.2 10.1 0.1 – December 31, 2014 13.1 12.6 0.5 – December 31, 2015 14.8 14.7 0.1 – December 31, 2016 20.3 15.6 4.7 – Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 201 3 – 201 6 – Continued 201 6 Comments for Proved Natural Gas Liquids Reserves Changes Revision s of previous estimates – The positive 2016 NGL proved reserves revision was primarily in the Eagle Ford Shale area based on an updated ratio of oil and gas production. Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area. Purchase of properties – In Canada , proved NGL reserves were added following the acquisition of acreage in both the Kabob Duvernay and liquids rich Placid Montney areas. 201 5 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2015 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale area based on improved performance. Extensions and discoveries – In 2015, the U.S. added NGL reserves primarily for additional drilling activities in the Eagle Ford Shale. Sales of properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015. 201 4 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2014 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale based on an overall review of oil and gas mix for this production area. Extensions and discoveries – The 2014 proved NGL reserves add in the U.S. was primarily attributable to drilling activities in the Eagle Ford Shale. The proved reserves add for Canadian NGL in 2014 was primarily associated with the drilling program in the Tupper and Tupper West areas. Sales of properties – The Company sold 20% of its oil and gas assets in Malaysia in late 2014. Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 201 3 – 201 6 ( Billions of cubic feet ) Total United States Canada Malaysia Proved developed and undeveloped natural gas reserves: December 31, 2013 1,153.6 185.0 562.8 405.8 Revisions of previous estimates 167.2 47.7 105.6 13.9 Improved recovery 7.0 – – 7.0 Extensions and discoveries 696.8 24.1 231.5 441.2 Purchases of properties 5.5 5.5 – – Sales of properties (162.6) (3.7) – (158.9) Production (162.8) (32.3) (57.1) (73.4) December 31, 2014 1,704.7 226.3 842.8 635.6 Revisions of previous estimates 53.5 (5.2) 18.9 39.8 Improved recovery 1.8 – – 1.8 Extensions and discoveries 162.9 43.2 119.7 – Sales of properties (78.0) – – (78.0) Production (156.1) (31.9) (71.8) (52.4) December 31, 2015 1,688.8 232.4 909.6 546.8 Revisions of previous estimates 43.3 0.1 45.3 (2.1) Extensions and discoveries 164.2 6.4 120.2 37.6 Purchases of properties 122.3 – 122.3 – Sales of properties (2.2) (0.1) (2.1) – Production (138.4) (19.4) (76.4) (42.6) December 31, 2016 1,878.0 219.4 1,118.9 539.7 Proved developed natural gas reserves: December 31, 2013 786.2 112.6 384.0 289.6 December 31, 2014 812.1 145.6 467.4 199.1 December 31, 2015 783.5 148.3 453.5 181.7 December 31, 2016 818.1 138.7 498.9 180.5 Proved undeveloped natural gas reserves: December 31, 2013 367.4 72.4 178.8 116.2 December 31, 2014 892.6 80.7 375.4 436.5 December 31, 2015 905.3 84.1 456.1 365.1 December 31, 2016 1,059.9 80.7 620.0 359.2 Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 201 3 – 201 6 – Continued 201 6 Comments for Proved Natural Gas Reserves Changes Revision s of previous estimates – The 2016 posi tive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada. The negative revision for natural gas reserves in Malaysia was primarily attributable to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans. Extensions and discoveries – In 2016, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural g as reserve adds in Canada were attributable to developmental drilling activities in the Tupper area. In Malaysia, proved natural g as reserves were added in Block H as the Permai field was added to the field development plan . Purchase of properties – In Canada , proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas. Sales of properties – Proved natural gas reserves were re duced following the sale of certain non-core Eagle Ford Shale acreage in the U.S., and the associated gas related to the sale of a heavy oil field in Canada. 201 5 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – The 2015 negative natural gas revision in the U.S. was primarily attributable to performance declines in certain fields in the Gulf of Mexico offset in part by the overall positive performance in the Eagle Ford Shale area. The positive revisions in Canada were attributable to updated well type curves and field development techniques in the Montney area of Western Canada. The positive revision for natural gas reserves in Malaysia was attributable to lower government entitlement under the terms of the respective production sharing contracts due to lower natural gas prices. Improved recovery – The 2015 Malaysia natural gas proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields. Extensions and discoveries – In 2015, the U.S. added natural gas reserves primarily for planned developmental drilling activities in the Eagle Ford Shale while the gas reserve adds in Canada were attributable to developmental drilling activities in the Tupper area. Sales o f properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015. 2014 Comments for Proved Natural Gas Reserves Changes Extensions and discoveries – The proved reserves of natural gas added in the U.S. in 2014 was primarily associated with the development drilling program in the Eagle Ford Shale, while the add in Canada in 2014 was attributable to drilling in the Tupper and Tupper West areas in Western Canada. The proved natural gas reserves added in Malaysia in 2014 was mostly associated with approval and sanction of the plan for a floating liquefied natural gas development in Block H, offshore Sabah, during 2014. Purchases of properties – The Company acquired an interest in the Kodiak field in the Gulf of Mexico in 2014, which added proved reserves of natural gas during 2014. Sales of properties – The Company sold its interests in South Louisiana gas fields in 2014, plus it sold a 20% interest in oil and gas assets in Malaysia late in 2014. Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities ( Millions of dollars ) United States Canada Malaysia Other Total Year ended December 31, 2016 Property acquisition costs Unproved $ 18.6 – – – 18.6 Proved – 206.7 – – 206.7 Total acquisition costs 18.6 206.7 – – 225.3 Exploration costs* 18.5 3.6 6.0 42.0 70.1 Development costs* 239.7 165.1 102.9 0.3 508.0 Total costs incurred 276.8 375.4 108.9 42.3 803.4 Charged to expense Dry hole expense 0.4 – 4.5 10.2 15.1 Geophysical and other costs 5.7 3.6 0.7 33.4 43.4 Total charged to expense 6.1 3.6 5.2 43.6 58.5 Property additions $ 270.7 371.8 103.7 (1.3) 744.9 Year ended December 31, 2015 Property acquisition costs Unproved $ 10.1 2.5 – – 12.6 Proved – – – – – Total acquisition costs 10.1 2.5 – – 12.6 Exploration costs* 166.8 0.7 69.0 135.4 371.9 Development costs* 1,375.1 231.5 210.0 2.8 1,819.4 Total costs incurred 1,552.0 234.7 279.0 138.2 2,203.9 Charged to expense Dry hole expense 241.3 – 29.7 25.8 296.8 Geophysical and other costs 16.9 0.7 7.9 73.2 98.7 Total charged to expense 258.2 0.7 37.6 99.0 395.5 Property additions $ 1,293.8 234.0 241.4 39.2 1,808.4 Year ended December 31, 2014 Property acquisition costs Unproved $ 92.9 – – – 92.9 Proved 7.4 – – – 7.4 Total acquisition costs 100.3 – – – – 100.3 Exploration costs* 160.0 1.7 6.3 262.1 430.1 Development costs* 1,934.7 413.8 926.6 7.6 3,282.7 Total costs incurred 2,195.0 415.5 932.9 269.7 3,813.1 Charged to expense Dry hole expense 92.1 – 47.4 130.5 270.0 Geophysical and other costs 37.7 1.7 1.3 128.5 169.2 Total charged to expense 129.8 1.7 48.7 259.0 439.2 Property additions $ 2,065.2 413.8 884.2 10.7 3,373.9 * Inclu des non cash asset retirement costs as follows: 2016 Exploration costs $ – – – – – Development costs 0.9 10.5 2.3 – 13.7 $ 0.9 10.5 2.3 – 13.7 2015 Exploration costs $ – – – – – Development costs 30.7 49.1 (3.0) – 76.8 $ 30.7 49.1 (3.0) – 76.8 2014 Exploration costs $ – – – – – Development costs 36.5 (32.1) 66.2 – 70.6 $ 36.5 (32.1) 66.2 – 70.6 Schedule 5 – Results of Operations for Oil and Gas Producing Activities * Canada United Conven- ( Millions of dollars ) States tional Synthetic Malaysia Other Total Year ended December 31, 2016 Revenues Crude oil and natural gas liquids sales $ 650.7 171.7 60.7 623.7 – 1,506.8 Natural gas sales 35.1 130.0 – 127.6 292.7 Total oil and gas revenues 685.8 301.7 60.7 751.3 – 1,799.5 Other operating revenues (0.1) (0.7) 3.6 2.1 0.2 5.1 Total revenues 685.7 301.0 64.3 753.4 0.2 1,804.6 Costs and expenses Lease operating expenses 218.6 102.6 69.8 168.4 – 559.4 Severance and ad valorem taxes 37.0 4.3 2.5 – – 43.8 Exploration costs charged to expense 6.1 3.6 – 5.2 43.6 58.5 Undeveloped lease amortization 38.4 4.5 – – 0.5 43.4 Depreciation, depletion and amortization 600.5 186.7 16.5 227.7 5.9 1,037.3 Accretion of asset retirement obligations 17.1 10.9 2.4 16.3 – 46.7 Impairment of assets – 95.1 – – – 95.1 Redetermination expense – – – 39.1 – 39.1 Deepwater rig contract exit benefit (4.3) – – – – (4.3) Selling and general expenses 68.8 28.6 0.5 15.9 33.6 147.4 Other expenses (benefits) (3.2) 7.5 – 23.8 (9.9) 18.2 Total costs and expenses 979.0 443.8 91.7 496.4 73.7 2,084.6 Results of operations before taxes (293.3) (142.8) (27.4) 257.0 (73.5) (280.0) Income tax expense (benefit) (87.9) (58.9) (75.4) 85.9 (18.8) (155.1) Results of operations $ (205.4) (83.9) 48.0 171.1 (54.7) (124.9) Year ended December 31, 2015 Revenues Crude oil and natural gas liquids sales $ 1,176.9 181.0 203.0 790.6 – 2,351.5 Natural gas sales 70.4 167.7 – 185.4 423.5 Total oil and gas revenues 1,247.3 348.7 203.0 976.0 – 2,775.0 Other operating revenues 6.3 (2.4) 0.4 155.4 – 159.7 Total revenues 1,253.6 346.3 203.4 1,131.4 – 2,934.7 Costs and expenses Lease operating expenses 312.0 102.4 166.0 251.9 – 832.3 Severance and ad valorem taxes 55.9 4.8 5.1 – – 65.8 Exploration costs charged to expense 258.2 0.7 – 37.6 99.0 395.5 Undeveloped lease amortization 59.2 14.4 – – 1.8 75.4 Depreciation, depletion and amortization 794.9 211.2 50.7 544.9 6.2 1,607.9 Accretion of asset retirement obligations 20.2 7.2 5.4 15.9 – 48.7 Impairment of assets 329.0 683.6 – 1,480.6 – 2,493.2 Deepwater rig contract exit costs 282.0 – – – – 282.0 Selling and general expenses 88.2 25.5 1.0 5.7 56.8 177.2 Other expense 6.7 43.9 – 15.9 12.1 78.6 Total costs and expenses 2,206.3 1,093.7 228.2 2,352.5 175.9 6,056.6 Results of operations before taxes (952.7) (747.4) (24.8) (1,221.1) (175.9) (3,121.9) Income tax expense (benefit) (337.0) (191.2) 2.4 (567.9) (17.3) (1,111.0) Results of operations $ (615.7) (556.2) (27.2) (653.2) (158.6) (2,010.9) * Results exclude corporate overhead, interest and discontinued operations. Schedule 5 – Results of Operations for Oil and Gas Producing Activities * – Continued Canada United Conven- ( Millions of dollars ) States tional Synthetic Malaysia Other Total Year ended December 31, 2014 Revenues Crude oil and natural gas liquids sales $ 2,062.1 453.3 391.5 1,680.2 – 4,587.1 Natural gas sales 127.2 201.3 – 357.5 – 686.0 Total oil and gas revenues 2,189.3 654.6 391.5 2,037.7 – 5,273.1 Other operating revenues 7.1 (2.4) 0.4 145.8 (1.3) 149.6 Total revenues 2,196.4 652.2 391.9 2,183.5 (1.3) 5,422.7 Costs and expenses Lease operating expenses 345.5 160.3 233.8 350.3 – 1,089.9 Severance and ad valorem taxes 96.5 5.6 5.1 – – 107.2 Exploration costs charged to expense 129.8 1.7 – 48.7 259.0 439.2 Undeveloped lease amortization 50.1 19.4 – – 4.9 74.4 Depreciation, depletion and amortization 840.7 262.7 54.0 735.0 5.1 1,897.5 Accretion of asset retirement obligations 17.5 6.0 9.2 18.1 – 50.8 Impairment of assets 14.3 37.0 – – – 51.3 Selling and general expenses 95.2 26.7 0.9 15.7 73.5 212.0 Other expenses 4.9 1.0 – 16.9 2.1 24.9 Total costs and expenses 1,594.5 520.4 303.0 1,184.7 344.6 3,947.2 Results of operations before taxes 601.9 131.8 88.9 998.8 (345.9) 1,475.5 Income tax expense (benefit) 214.8 42.4 21.8 102.6 (95.9) 285.7 Results of operations $ 387.1 89.4 67.1 896.2 (250.0) 1,189.8 * Results exclude corporate overhead, interest and discontinued operations. Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves ( Millions of dollars ) United States Canada Malaysia Total December 31, 2016 Future cash inflows $ 9,477.9 3,752.7 4,318.7 17,549.3 Future development costs (1,691.1) (1,143.6) (763.8) (3,598.5) Future production costs (3,981.6) (2,329.7) (2,661.2) (8,972.5) Future income taxes (118.9) (81.3) (73.3) (273.5) Future net cash flows 3,686.3 198.1 820.4 4,704.8 10% annual discount for estimated timing of cash flows (1,799.5) (95.0) (230.3) (2,124.8) Standardized measure of discounted future net cash flows $ 1,886.8 103.1 590.1 2,580.0 December 31, 2015 Future cash inflows $ 12,373.9 8,922.0 6,143.1 27,439.0 Future development costs (2,620.5) (1,145.4) (957.8) (4,723.7) Future production costs (4,955.4) (5,892.7) (3,290.5) (14,138.6) Future income taxes (339.7) (504.8) (216.2) (1,060.7) Future net cash flows 4,458.3 1,379.1 1,678.6 7,516.0 10% annual discount for estimated timing of cash flows (2,430.0) (666.8) (560.1) (3,656.9) Standardized measure of discounted future net cash flows $ 2,028.3 712.3 1,118.5 3,859.1 December 31, 2014 Future cash inflows $ 20,767.4 16,257.0 11,909.7 48,934.1 Future development costs (3,151.4) (1,810.5) (1,920.8) (6,882.7) Future production costs (6,378.5) (7,770.2) (4,575.6) (18,724.3) Future income taxes (2,930.1) (1,389.6) (1,249.9) (5,569.6) Future net cash flows 8,307.4 5,286.7 4,163.4 17,757.5 10% annual discount for estimated timing of cash flows (3,729.1) (2,595.3) (1,527.9) (7,852.3) Standardized measure of discounted future net cash flows $ 4,578.3 2,691.4 2,635.5 9,905.2 Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves – Continued Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. ( Millions of dollars ) 2016 2015 2014 Net changes in prices and production costs $ (1,476.1) (11,365.5) (2,697.8) Net changes in development costs 544.9 591.4 (2,317.3) Sales and transfers of oil and gas produced, net of production costs (1,196.3) (1,876.9) (4,076.0) Net change due to extensions and discoveries 280.5 1,145.8 3,251.6 Net change due to purchases and sales of proved reserves (583.4) (287.4) (1,041.0) Development costs incurred 479.6 1,725.4 3,169.3 Accretion of discount 428.1 1,289.5 1,462.5 Revisions of previous quantity estimates (49.2) 163.3 518.9 Net change in income taxes 292.8 2,568.3 790.3 Net increase (decrease) (1,279.1) (6,046.1) (939.5) Standardized measure at January 1 3,859.1 9,905.2 10,844.7 Standardized measure at December 31 $ 2,580.0 3,859.1 9,905.2 Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities ( Millions of dollars ) United States Canada Malaysia Other Subtotal Synthetic Oil – Canada Total December 31, 2016 Unproved oil and gas properties $ 360.8 315.6 47.0 125.6 849.0 – 849.0 Proved oil and gas properties 9,384.6 4,241.6 6,147.8 – 19,774.0 – 19,774.0 Gross capitalized costs 9,745.4 4,557.2 6,194.8 125.6 20,623.0 – 20,623.0 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (151.2) (233.6) – (21.8) (406.6) – (406.6) Proved oil and gas properties (4,605.9) (2,877.2) (4,566.6) – (12,049.7) – (12,049.7) Net capitalized costs $ 4,988.3 1,446.4 1,628.2 103.8 8,166.7 – 8,166.7 December 31, 2015 Unproved oil and gas properties $ 570.3 283.1 28.6 128.5 1,010.5 – 1,010.5 Proved oil and gas properties 9,010.0 4,062.2 6,216.0 – 19,288.2 1,174.7 20,462.9 Gross capitalized costs 9,580.3 4,345.3 6,244.6 128.5 20,298.7 1,174.7 21,473.4 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (220.8) (219.4) – (22.4) (462.6) – (462.6) Proved oil and gas properties (4,004.9) (2,586.0) (4,336.9) – (10,927.8) (410.7) (11,338.5) Net capitalized costs $ 5,354.6 1,539.9 1,907.7 106.1 8,908.3 764.0 9,672.3 Note: Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation. |
Supplemental Quarterly Inofrmat
Supplemental Quarterly Inofrmation | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Information [Abstract] | |
Supplemental Quaterly Information | ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year Year ended December 31, 2016 Sales and other operating revenues $ 429.1 411.2 486.3 483.0 1,809.6 Income (loss) from continuing operations before income taxes (265.0) (131.3) (16.7) (80.1) (493.1) Income (loss) from continuing operations (199.5) 2.9 (14.6) (62.8) (274.0) Net income (loss) (198.8) 2.9 (16.2) (63.9) (276.0) Income (loss) from continuing operations per Common share Basic (1.16) 0.02 (0.08) (0.36) (1.59) Diluted (1.16) 0.02 (0.08) (0.36) (1.59) Net income (loss) per Common share Basic (1.16) 0.02 (0.08) (0.37) (1.60) Diluted (1.16) 0.02 (0.08) (0.37) (1.60) Cash dividend per Common share 0.35 0.35 0.25 0.25 1.20 Market price of Common Stock* High 26.69 36.24 32.66 34.30 36.24 Low 15.76 23.49 25.14 25.00 15.76 Year ended December 31, 2015 Sales and other operating revenues $ 749.2 718.6 665.6 653.7 2,787.1 Income from continuing operations before income taxes (117.7) (110.1) (2,408.0) (646.5) (3,282.3) Income from continuing operations 3.5 (89.0) (1,587.1) (583.2) (2,255.8) Net income (14.5) (73.8) (1,595.4) (587.1) (2,270.8) Income from continuing operations per Common share Basic 0.02 (0.51) (9.22) (3.39) (12.94) Diluted 0.02 (0.51) (9.22) (3.39) (12.94) Net income per Common share Basic (0.08) (0.42) (9.26) (3.41) (13.03) Diluted (0.08) (0.42) (9.26) (3.41) (13.03) Cash dividend per Common share 0.35 0.35 0.35 0.35 1.40 Market price of Common Stock* High 51.77 50.56 41.42 31.03 51.77 Low 43.40 41.42 23.76 21.71 21.71 * Prices are as quoted on the New York Stock Exchange. |
Valuation Accounts and Reserves
Valuation Accounts and Reserves | 12 Months Ended |
Dec. 31, 2016 | |
Valuation Accounts and Reserves [Abstract] | |
Valuation Accounts and Reserves | ( Millions of dollars ) Balance at January 1 Charged (Credited) to Expense Deductions Other* Balance at December 31 2016 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 – – – 1.6 Deferred tax asset valuation allowance 294.4 25.7 – (14.7) 305.4 2015 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 – – – 1.6 Deferred tax asset valuation allowance 306.5 40.8 – (52.9) 294.4 2014 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 – – – 1.6 Deferred tax asset valuation allowance 633.7 37.7 – (364.9) 306.5 * Amount in 2016 for deferred tax asset valuations is primarily associated with an increase in foreign tax credit carry forwards. Amount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carry forwards. Amount in 2014 for deferred tax asset valuation allowance is primarily associated with final abandonment of certain foreign investments in 2014, essentially offsetting changes in deferred tax assets. |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Significant Accounting Policies [Abstract] | |
Nature of Business | NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and entered into an agreement to sale its Canadian heavy oil assets in December 2016. In addition, Murphy Oil sold its remaining downstream assets in the United Kingdom in 2015 and its U.K. retail marketing assets during 2014. See Note C regarding more information regarding the sale of these assets |
Principles of Consolidation | PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated. |
Revenue Recognition | REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2016 and 2015, the liabilities for natural gas balancing were immaterial. |
Cash Equivalents | CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents. |
Marketable Securities | MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2016, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $111,542,000 . These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada. |
Accounts Receivable | ACCOUNTS RECEIVABLE – At December 31, 2016 and 2015, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years. |
Inventories | INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment. |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete. Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. During 2016 and 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2016, the Company recognized pretax noncash impairments charges of approximately $95,088,000 at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairments charges of $2,493,200,000 , to reduce the carrying value of certain producing properties in Malaysia, Western Canada and the Gulf of Mexico to their estimated fair value. See also Note E for further discussion of impairment charges. The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves; unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being depreciated on a straight-line basis over its estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in income (loss) as a separate component of revenues. Turnarounds for coking units at Syncrude Canada Ltd. were scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varied depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease operating expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. The Company sold its interest in Syncrude during 2016. |
Capitalized Interest | Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, Plant and Equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs. |
Goodwill | GOODWILL – Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired. Goodwill is not amortized, but is assessed annually for recoverability of the carrying value. The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties with the carrying value of these net assets including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company recorded an impairment charge of $37,047,000 in 2014 and reduced the carrying amount to zero . |
Environmental Liabilities | ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. |
Income Taxes | INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. The Company does not provide U.S. deferred taxes for the portion of undistributed earnings of foreign subsidiaries when these earnings are considered indefinitely reinvested in the respective foreign operations. The unrecognized deferred tax liability is dependent on many factors including withholding taxes under current tax treaties, any repatriation occurring while the U.S. is in a taxable income position, and associated foreign tax credits. Under present law, the Company would incur a 5% withholding tax on any monies repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense. |
Foreign Currency | FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity. |
Derivative Instruments and Hedging Activities | DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in other comprehensive loss until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in other comprehensive loss is recognized immediately in earnings. |
Fair Value Measurements | Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants |
Stock-based Compensation | STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock prices. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three -year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the three-year vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards |
Pension and Other Postretirement Benefit Plans | PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Statement of Operations are recorded net of tax in Accumulated Other Comprehensive Loss. The remaining amounts in Accumulated Other Comprehensive Loss as of December 31, 2016 include net actuarial losses and prior service (cost) credit. |
Net Income (Loss) Per Common Share | NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share. |
Use of Estimates | USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates |
Discontinued Operations and A36
Discontinued Operations and Assets Held for Sale (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Assets Held for Sale [Abstract] | |
Major Categories of Assets and Liabilities Reflected as Held for Sale | ( Thousands of dollars ) 2016 2015 Current assets Cash $ 4,126 7,927 Accounts receivable 22,944 29,358 Other – 1,055 Total current assets held for sale $ 27,070 38,340 Current liabilities Accounts payable $ 270 2,433 Accrued compensation and severance – 2,179 Refinery decommissioning cost 2,506 2,685 Total current liabilities associated with assets held for sale $ 2,776 7,297 Non-current liabilities Asset retirement obligation – Seal asset $ 85,900 – Total non-current liabilities associated with assets held for sale $ 85,900 – |
Results of Operations Associated with Discontinued Operations | ( Thousands of dollars ) 2016 2015 2014 Revenues $ – 381,747 2,786,394 Loss from operations before income taxes $ (2,027) (6,758) (261,873) Gain (loss) on sale before income taxes – (4,990) 101,684 Total loss from discontinued operations before taxes (2,027) (11,748) (160,189) Income tax expense (benefit) – 3,313 (40,827) Loss from discontinued operations $ (2,027) (15,061) (119,362) |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Inventories [Abstract] | |
Schedule of Inventory | December 31, 2016 2015 ( Thousands of dollars ) Unsold crude oil $ 17,146 25,583 Materials and supplies 109,925 141,205 $ 127,071 166,788 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant And Equipment [Abstract] | |
Schedule of Property, Plant and Equipment | December 31, 2016 December 31, 2015 ( Thousands of dollars ) Cost Net Cost Net Exploration and production 1 $ 20,767,772 8,214,740 2 21,607,962 9,723,222 2 Corporate and other 156,231 101,448 134,596 95,143 $ 20,924,003 8,316,188 21,742,558 9,818,365 1 Includes mineral rights as follows: $ 595,138 188,689 1,075,040 612,518 2. Includes $48,053 in 2016 and $50,924 in 2015 related to administrative assets and support equipment. |
Schedule of Recognized Impairments | December 31, ( Thousands of dollars ) 2016 2015 2014 Gulf of Mexico $ – 328,982 14,267 Canada 95,088 683,574 37,047 * Malaysia – 1,480,600 – $ 95,088 2,493,156 51,314 * This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. |
Net Changes in Capitalized Exploratory Well Costs | ( Thousands of dollars ) 2016 2015 2014 Beginning balance at January 1 $ 130,514 120,455 393,030 Additions to capitalized exploratory well costs pending the determination of proved reserves 17,986 64,578 2,874 Reclassifications to proved properties based on the determination of proved reserves – – (91,236) Reduction of capitalized exploratory well costs due to partial asset sale in Malaysia – – (122,175) Capitalized exploratory well costs charged to expense – (54,519) (62,038) Ending balance at December 31 $ 148,500 130,514 120,455 |
Aging of Capitalized Exploratory Well Costs | 2016 2015 2014 ( Thousands of dollars ) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Aging of capitalized well costs: Zero to one year $ 20,481 1 1 $ 66,032 7 6 $ – – – One to two years 63,527 5 5 – – – 59,330 3 1 Two to three years – – – 57,876 3 – 6,606 3 – Three years or more 64,492 6 – 6,606 3 – 54,519 2 2 $ 148,500 12 6 $ 130,514 13 6 $ 120,455 8 3 |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Financing Arrangements [Abstract] | |
Schedule of Long-term Debt | December 31, (Thousands of dollars ) 2016 2015 Notes payable 2.50% notes, due December 2017 * $ 550,000 550,000 4.00% notes, due June 2022 500,000 500,000 3.70% notes, due December 2022 * 600,000 600,000 6.875% notes, due August 2024 550,000 - 7.05% notes, due May 2029 250,000 250,000 5.125% notes, due December 2042 * 350,000 350,000 Notes payable to banks, 1.4375% at December 31 - 600,000 Total notes payable 2,800,000 2,850,000 Unamortized discount on notes payable (23,835) (19,223) Total notes payable, net of unamortized discount 2,776,165 2,830,777 Capitalized lease obligation, due through March 2029 216,402 228,698 Total debt including current maturities 2,992,567 3,059,475 Current maturities (569,817) (18,881) Total long-term debt $ 2,422,750 3,040,594 * The interest rate paid is 1.0% above rate shown due to a downgrade of the credit rating for the Company’s no tes in February 2016. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations | ( Thousands of dollars ) 2016 2015 Balance at beginning of year $ 825,312 875,728 Accretion expense 46,742 48,665 Liabilities incurred 13,690 76,775 Revisions of previous estimates (4,511) (85,504) Liabilities settled (20,589) (13,359) Liabilities assumed by purchaser of oil and gas assets (91,883) (33,448) Changes due to translation of foreign currencies 12,296 (43,545) Balance at end of year 781,057 825,312 Liabilities reported as held for sale at end of year 1 (85,900) – Current portion of liability at end of year 2 (13,629) (31,838) Noncurrent portion of liability at end of year $ 681,528 793,474 1 Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. 2 Included in Other Accrued Liabilities on the Consolidated Balance Sheet. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense | ( Thousands of dollars ) 2016 2015 2014 Income (loss) from continuing operations before income taxes United States $ (595,196) (1,259,268) 179,484 Foreign 102,081 (2,022,994) 1,072,786 Total $ (493,115) (3,282,262) 1,252,270 Income tax expense (benefit) Federal – Current $ - (9,435) 25,151 – Deferred (197,450) (241,127) 25,444 (197,450) (250,562) 50,595 State 13,984 (5,294) 8,840 Foreign – Current 146,861 (40,550) 359,502 – Deferred (182,567) (730,084) (191,640) (35,706) (770,634) 167,862 Total $ (219,172) (1,026,490) 227,297 |
Effective Income Tax Rates | ( Thousands of dollars ) 2016 2015 2014 Income tax expense (benefit) based on the U.S. statutory tax rate $ (172,590) (1,148,792) 438,295 Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 8,582 49,739 20,562 State income taxes, net of federal benefit 9,090 (3,441) 5,746 U.S. tax benefit on certain foreign upstream investments (21,336) (16,939) (95,838) Current tax on distribution of foreign earnings – – 52,724 Deferred tax on distribution of foreign earnings – 188,461 – Tax effects on sale of Canadian assets (89,473) – – Tax effects on sale of Malaysian assets 2,080 (122,559) (227,241) Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures 25,734 40,788 37,712 Other, net 18,741 (13,747) (4,663) Total $ (219,172) (1,026,490) 227,297 |
Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences | ( Thousands of dollars ) 2016 2015 Deferred tax assets Property and leasehold costs $ 572,481 587,517 Liabilities for dismantlements 170,946 114,565 Postretirement and other employee benefits 214,288 226,217 Alternative minimum tax 29,710 39,683 Foreign tax credit carryforwards 33,295 855 U. S. net operating loss 454,231 – Other deferred tax assets 16,541 127,165 Total gross deferred tax assets 1,491,492 1,096,002 Less valuation allowance (305,389) (294,406) Net deferred tax assets 1,186,103 801,596 Deferred tax liabilities Accumulated depreciation, depletion and amortization (867,343) (793,972) Other deferred tax liabilities (21,908) (21,095) Total gross deferred tax liabilities (889,251) (815,067) Net deferred tax assets (liabilities) $ 296,852 (13,471) |
Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits | ( Thousands of dollars ) 2016 2015 2014 Balance at January 1 $ 6,631 6,011 6,366 Additions for tax positions related to current year 756 821 988 Settlements due to lapse of time – – (1,225) Foreign currency translation effect 30 (201) (118) Balance at December 31 $ 7,417 6,631 6,011 |
Incentive Plans (Tables)
Incentive Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Incentive Plans [Abstract] | |
Share-Based Plans, Amounts Recognized | ( Thousands of dollars ) 2016 2015 2014 Compensation charged against income (loss) before income tax benefit $ 46,300 44,021 53,157 Related income tax benefit recognized in income 15,244 13,583 15,604 |
Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model | 2016 2015 2014 Fair value per option grant $5.03 $10.97 – $11.08 $12.84 Assumptions Dividend yield 4.00% 2.40% – 2.50% 2.00% Expected volatility 45.00% 29.00% – 30.00% 29.00% Risk-free interest rate 1.32% 1.34% – 1.60% 1.62% Expected life 5.20 yrs. 5.30 yrs. 5.35 yrs. |
Changes in Stock Options Outstanding | Number of Shares Average Exercise Price Outstanding at December 31, 2013 6,006,585 $ 56.80 Granted at FMV 772,900 55.82 Exercised (862,407) 49.27 Forfeited (314,828) 54.53 Outstanding at December 31, 2014 5,602,250 57.95 Granted at FMV 991,000 49.67 Exercised (32,349) 40.80 Forfeited (1,117,613) 31.99 Outstanding at December 31, 2015 5,443,288 52.93 Granted at FMV 862,000 17.57 Exercised – – Forfeited (547,853) 44.23 Outstanding at December 31, 2016 5,757,435 48.46 Exercisable at December 31, 2013 2,435,322 $ 51.79 Exercisable at December 31, 2014 3,030,105 53.10 Exercisable at December 31, 2015 3,542,352 52.26 Exercisable at December 31, 2016 3,830,535 53.80 |
Additional Information about Stock Options Outstanding | Options Outstanding Options Exercisable Range of Exercise Prices per Option No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value $17.57 to $39.02 892,350 5.9 $ 11,354,000 55,350 2.5 $ – $45.48 to $51.63 2,379,926 2.8 – 1,556,926 1.6 – $54.21 to $62.98 2,485,159 2.6 – 2,218,259 2.4 – 5,757,435 3.2 $ 11,354,000 3,830,535 2.0 $ – |
Changes in Performance-Based RSU Outstanding | ( Number of share units ) 2016 2015 2014 Outstanding at beginning of year 1,103,986 1,397,040 1,560,292 Granted 394,000 455,000 464,300 Awarded (361,096) (521,800) (473,186) Forfeited (144,317) (226,254) (154,366) Outstanding at end of year 992,573 1,103,986 1,397,040 |
Assumptions used in Valuation of Performance Awards Granted | 2016 2015 2014 Fair value per share at grant date $12.21 – $16.34 $44.03 – $48.12 $33.90 – $51.30 Assumptions Expected volatility 33.00% 26.00% 29.00% Risk-free interest rate 0.93% 0.85% 0.65% Stock beta 0.863 0.813 0.843 Expected life 3.0 yrs. 3.0 yrs. 3.0 yrs. |
Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding | ( Number of share units ) 2016 2015 2014 Outstanding at beginning of year 477,244 321,789 112,881 Granted 503,555 282,065 278,892 Vested and issued (32,092) (69,610) (54,884) Forfeited (25,425) (57,000) (15,100) Outstanding at end of year 923,282 477,244 321,789 |
Employee and Retiree Benefit 43
Employee and Retiree Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Pension And Other Postretirement Benefits Disclosure [Line Items] | |
Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense | ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits Net actuarial loss $ (247,622) (2,858) Prior service (cost) credit (6,831) 112 $ (254,453) (2,746) |
Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense | ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits Net actuarial loss $ (14,257) – Prior service (cost) credit (1,019) 74 $ (15,276) 74 |
Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets | Projected Benefit Obligations Accumulated Benefit Obligations Fair Value of Plan Assets ( Thousands of dollars ) 2016 2015 2016 2015 2016 2015 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 643,174 630,587 599,730 622,841 497,894 500,695 Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets 156,088 148,019 150,780 140,544 – – Unfunded other postretirement plans 106,678 115,222 106,678 115,222 – – |
Components of Net Periodic Benefit Expense | Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2014 2016 2015 2014 Service cost $ 8,136 17,948 22,470 1,864 3,180 2,459 Interest cost 25,185 33,168 33,680 3,800 4,883 4,617 Expected return on plan assets (28,154) (34,016) (33,723) – – – Amortization of prior service cost (credit) 1,204 1,560 899 (75) (82) (82) Amortization of transitional (asset) liability – (1) (480) – – – Recognized actuarial loss 16,165 15,147 9,471 5 992 5 22,536 33,806 32,317 5,594 8,973 6,999 Termination benefits expense – 8,606 – – – – Curtailment expense 822 306 – (19) – – Net periodic benefit expense $ 23,358 42,718 32,317 5,575 8,973 6,999 |
Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense | Benefit Obligations Net Periodic Benefit Expense Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31 December 31 Year Year 2016 2015 2016 2015 2016 2015 2016 2015 Discount rate 3.94% 4.37% 4.41% 4.61% 3.84% 4.04% 4.24% 4.12% Expected return on plan assets 5.62% 6.00% – – 5.62% 6.00% – – Rate of compensation increase 3.52% 3.74% – – 3.52% 3.74% – – |
Benefit Payments Reflecting Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company | ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits 2017 $ 38,532 6,161 2018 38,896 6,319 2019 39,833 6,435 2020 40,848 6,621 2021 41,653 6,824 2022-2026 221,350 36,326 |
One Percent Change in Assumed Health Care Cost Trend Rates | ( Thousands of dollars ) 1% Increase 1% Decrease Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2016 $ 1,076 (818) Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2016 15,246 (12,251) |
Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets | ( Thousands of dollars ) Hedged Funds and Other Alternative Strategies Total at December 31, 2014 $ 33,952 Actual return on plan assets: Relating to assets held at the reporting date (23) Relating to assets sold during the period – Purchases, sales and settlements – Total at December 31, 2015 33,929 Actual return on plan assets: Relating to assets held at the reporting date 185 Relating to assets sold during the period – Purchases, sales and settlements – Total at December 31, 2016 $ 34,114 |
Domestic Postretirement Plans [Member] | |
Pension And Other Postretirement Benefits Disclosure [Line Items] | |
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status | Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 794,589 825,552 115,222 118,496 Service cost 8,136 17,948 1,864 3,180 Interest cost 25,185 33,168 3,800 4,883 Plan amendments – 8,297 – – Participant contributions – 4 1,278 1,276 Actuarial loss (gain) 58,236 (48,019) (10,627) (7,436) Medicare Part D subsidy – – 510 510 Exchange rate changes (30,447) (15,337) 20 (112) Benefits paid (40,928) (35,936) (5,369) (5,575) Special termination benefits – 8,606 – – Curtailments 822 306 (19) – Obligation at December 31 815,593 794,589 106,679 115,222 Change in plan assets Fair value of plan assets at January 1 521,682 560,978 – – Actual return on plan assets 61,860 (18,718) – – Employer contributions 8,186 31,442 3,581 3,789 Participant contributions – 4 1,278 1,276 Medicare Part D subsidy – – 510 510 Exchange rate changes (30,609) (14,104) – – Benefits paid (40,928) (35,936) (5,369) (5,575) Other (834) (1,984) – – Fair value of plan assets at December 31 519,357 521,682 – – Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 7,591 7,463 – – Other accrued liabilities (8,184) (7,487) (5,267) (5,370) Deferred credits and other liabilities (295,643) (272,883) (101,412) (109,852) Funded status and net plan liability recognized at December 31 $ (296,236) (272,907) (106,679) (115,222) |
Foreign Other Postretirement Benefit Plans [Member] | |
Pension And Other Postretirement Benefits Disclosure [Line Items] | |
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status | Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2016 2015 2016 2015 Benefit obligation at December 31 $ 206,502 197,549 615 643 Fair value of plan assets at December 31 197,575 193,933 – – Net plan liabilities recognized 8,927 3,616 615 643 Net periodic benefit expense (benefit) (2,244) 4,703 154 152 |
Other Postretirement Benefits [Member] | |
Pension And Other Postretirement Benefits Disclosure [Line Items] | |
Asset Allocation for Benefit Plans | At December 31, 201 6 , the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 61,554 61,554 – – U.S. small/midcap 23,103 23,103 – – Hedged funds and other alternative strategies 48,113 – 13,999 34,114 International commingled trust fund 67,451 – 67,451 – Emerging market commingled equity fund 16,006 – 16,006 – Fixed income securities: U.S. fixed income 78,473 – 78,473 – International commingled trust fund 13,486 – 13,486 – Emerging market mutual fund 5,775 – 5,775 – Cash and equivalents 7,821 7,821 – – Total Domestic Plans 321,782 92,478 195,190 34,114 Foreign Plans Equity securities funds 74,108 – 74,108 – Fixed income securities funds 97,075 – 97,075 – Diversified pooled fund 21,463 – 21,463 – Cash and equivalents 4,929 – 4,929 – Total Foreign Plans 197,575 – 197,575 – Total $ 519,357 92,478 392,765 34,114 At December 31, 201 5 , the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 51,878 51,878 – – U.S. small/midcap 26,964 26,964 – – Hedged funds and other alternative strategies 50,878 – 16,949 33,929 International commingled trust fund 72,205 – 72,205 – Emerging market commingled equity fund 16,873 – 16,873 – Fixed income securities: U.S. fixed income 80,681 – 80,681 – International commingled trust fund 15,332 – 15,332 – Emerging market mutual fund 6,439 – 6,439 – Cash and equivalents 6,499 6,499 – – Total Domestic Plans 327,749 85,341 208,479 33,929 Foreign Plans Equity securities funds 104,718 – 104,718 – Fixed income securities funds 67,494 – 67,494 – Diversified pooled fund 20,987 – 20,987 – Cash and equivalents 734 734 – – Total Foreign Plans 193,933 734 193,199 – Total $ 521,682 86,075 401,678 33,929 |
Funded Defined Benefit Pension Plans [Member] | |
Pension And Other Postretirement Benefits Disclosure [Line Items] | |
Asset Allocation for Benefit Plans | December 31, 2016 2015 Equity securities 58.4 % 64.4 % Fixed income securities 39.0 34.0 Cash equivalents 2.6 1.6 100.0 % 100.0 % |
Financial Instruments and Ris44
Financial Instruments and Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Financial Instruments and Risk Management [Abstract] | |
Fair Value of Derivative Instruments Not Designated as Hedging Instruments | December 31, 2016 December 31, 2015 Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives ( Thousands of dollars ) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Type of Derivative Contract Commodity – – Accounts Payable $48,864 Accounts Receivable $89,358 – – Foreign exchange – – Accounts Payable $73 – – Accounts Payable $29 |
Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments | Year Ended December 31, 2016 Year Ended December 31, 2015 ( Thousands of dollars ) Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative Type of Derivative Contract Commodity Sale and Other Operating Revenues $ (63,412) Sale and Other Operating Revenues $ 129,064 Foreign exchange Interest and Other Income 26,714 Interest and Other Income (4) $ (36,698) $ 129,060 |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | |
Summary of Shares Repurchased | 2015 2014 Purchase of Treasury Stock $ 250,000,000 $ 375,000,000 Shares repurchased 5,967,313 6,373,718 |
Earnings per Share (Tables)
Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings per Share [Abstract] | |
Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share | ( Weighted-average shares ) 2016 2015 2014 Basic method 172,173,012 174,351,227 178,852,942 Dilutive stock options and restricted stock units * – – 1,218,042 Diluted method 172,173,012 174,351,227 180,070,984 * Due to a net loss recognized by the Company for the year ended December 31, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive. |
Anti Dilutive Securities Not Included in Computation of Diluted EPS | 2016 2015 2014 Antidilutive stock options excluded from diluted shares 5,757,435 5,443,288 1,893,364 Weighted average price of these options $48.46 $52.93 $55.21 |
Other Financial Information (Ta
Other Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Financial Information [Abstract] | |
Noncash Operating Working Capital (Increase) Decrease | ( Thousands of dollars ) 2016 2015 2014 Accounts receivable $ 119,671 297,625 175,820 Inventories (5,171) (15,340) 25,697 Prepaid expenses 149,946 (144,845) 6,575 Deferred income tax assets - 3,924 6,884 Accounts payable and accrued liabilities (328,078) (36,887) (54,785) Current income tax liabilities 24,943 (69,413) (163,920) Net (increase) decrease in noncash operating working capital $ (38,689) 35,064 (3,729) Supplementary disclosures (including discontinued operations): Cash income taxes paid, net of refunds $ 6,707 118,667 573,799 Interest paid, net of amounts capitalized 127,798 110,386 114,232 Noncash investing activities, related to continuing operations: Asset retirement costs capitalized $ 13,690 76,775 70,568 Decrease in capital expenditure accrual 158,885 462,474 93,080 |
Accumulated Other Comprehensi48
Accumulated Other Comprehensive Loss (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Loss [Abstract] | |
Components of Accumulated Other Comprehensive Loss | ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) 1 Retirement and Postretirement Benefit Plan Adjustments 1 Deferred Loss on Interest Rate Derivative Hedges 1 Total 1 Balance at December 31, 2014 $ 33,701 (189,752) (14,204) (170,255) 2015 components of other comprehensive income (loss): Before reclassifications to income (588,450) (5,468) – (593,918) Reclassifications to income 41,745 2 15,960 3 1,926 4 59,631 Net other comprehensive income (loss) (546,705) 10,492 1,926 (534,287) Balance at December 31, 2015 (513,004) (179,260) (12,278) (704,542) 2016 components of other comprehensive income (loss): Before reclassifications to income 66,449 (3,763) – 62,686 Reclassifications to income – 11,718 3 1,926 4 13,644 Net other comprehensive income 66,449 7,955 1,926 76,330 Balance at December 31, 2016 $ (446,555) (171,305) (10,352) (628,212) 1 All amounts are presented net of income taxes. 2 Reclassification for the year ended December 31, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K. 3 Reclassifications before taxes of $21,721 and $18,036 are included in the computation of net periodic benefit expense in 2015 and 2016 , respectively. See Note K for additional information. Related income taxes of $5,761 and $6,318 are included in income tax expense in 2015 and 2016 , respectively. 4 Reclassifications before taxes of $2,963 are included in Interest expense in both 2015 and 2016 . Related income taxes of $1,037 are includ ed in income tax expense in 2015 and 2016 . See Note L for additional information. |
Assets and Liabilities Measur49
Assets and Liabilities Measured at Fair Value (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Assets and Liabilities Measured at Fair Value [Abstract] | |
Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis | December 31, 2016 December 31, 2015 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity derivative contracts – – – – – 89,358 – 89,358 $ – – – – – 89,358 – 89,358 Liabilities: Nonqualified employee savings plans $ 13,904 – – 13,904 12,971 – – 12,971 Commodity derivative contracts – 48,864 – 48,864 – – – – Foreign currency exchange derivative contracts – 73 – 73 – 29 – 29 $ 13,904 48,937 – 62,841 12,971 29 – 13,000 |
Carrying Amounts and Estimated Fair Values of Financial Instruments | At December 31, 2016 2015 ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value Financial assets (liabilities): Canadian government securities with maturities greater than 90 days at the date of acquisition $ 111,542 111,331 173,288 173,234 Current and long-term debt (2,992,567) (2,951,992) (3,059,475) (2,189,858) |
Nonrecurring Fair Value Measurements | Year Ended December 31, 2016 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense Assets: Impaired proved properties Canada – – 71,967 167,055 95,088 $ – – 71,967 167,055 95,088 Year Ended December 31, 2015 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense Assets: Impaired proved properties Gulf of Mexico $ – – 316,106 645,088 328,982 Western Canada – – 23,526 707,100 683,574 Malaysia – – 1,200,900 2,681,500 1,480,600 $ – – 1,540,532 4,033,688 2,493,156 |
Common Stock Issued and Outst50
Common Stock Issued and Outstanding (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | |
Activity in Number of Shares of Common Stock Issued and Outstanding | ( Number of shares outstanding ) 2016 2015 2014 At beginning of year 172,034,711 177,499,513 183,406,513 Stock options exercised* - 15,575 119,994 Restricted stock awards* 158,504 478,549 339,985 Employee stock purchase and thrift plans 8,962 8,387 6,739 Treasury shares purchased - (5,967,313) (6,373,718) At end of year 172,202,177 172,034,711 177,499,513 * Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares . |
Business Segments (Tables)
Business Segments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Segments [Abstract] | |
Segment Information | Segment Information Exploration and Production ( Millions of dollars ) United States Canada Malaysia Other Total E&P Year ended December 31, 2016 Segment loss $ (205.4) (35.9) 171.1 (54.7) (124.9) Revenues from external customers 685.7 365.3 753.4 0.2 1,804.6 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) (87.9) (134.3) 85.9 (18.8) (155.1) Significant noncash charges (credits) Depreciation, depletion and amortization 600.5 203.2 227.7 5.9 1,037.3 Accretion of asset retirement obligations 17.1 13.3 16.3 – 46.7 Amortization of undeveloped leases 38.4 4.5 – 0.5 43.4 Impairment of assets – 95.1 – – 95.1 Deferred and noncurrent income taxes (108.4) (175.8) (8.5) (18.3) (311.0) Additions to property, plant, equipment 269.8 361.3 101.4 (1.3) 731.2 Total assets at year-end 5,419.0 1,559.5 2,024.7 115.7 9,118.9 Year ended December 31, 2015 Segment loss $ (615.7) (583.4) (653.2) (158.6) (2,010.9) Revenues from external customers 1,253.6 549.7 1,131.4 – 2,934.7 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax benefit (337.0) (188.8) (567.9) (17.3) (1,111.0) Significant noncash charges (credits) Depreciation, depletion and amortization 794.9 261.9 544.9 6.2 1,607.9 Accretion of asset retirement obligations 20.2 12.6 15.9 – 48.7 Amortization of undeveloped leases 59.2 14.4 – 1.8 75.4 Impairment of assets 329.0 683.6 1,480.6 – 2,493.2 Deferred and noncurrent income taxes (187.7) (146.0) (579.2) (4.6) (917.5) Additions to property, plant, equipment 1,263.1 184.9 244.4 39.2 1,731.6 Total assets at year-end 5,717.8 2,460.6 2,537.2 147.7 10,863.3 Year ended December 31, 2014 Segment income (loss) $ 387.1 156.5 896.2 (250.0) 1,189.8 Revenues from external customers 2,196.4 1,044.1 2,183.5 (1.3) 5,422.7 Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) 214.8 64.2 102.6 (95.9) 285.7 Significant noncash charges (credits) Depreciation, depletion and amortization 840.7 316.7 735.0 5.1 1,897.5 Accretion of asset retirement obligations 17.5 15.2 18.1 – 50.8 Amortization of undeveloped leases 50.1 19.4 – 4.9 74.4 Impairment of assets 14.3 37.0 – – 51.3 Deferred and noncurrent income taxes 39.7 43.3 (235.1) – (152.1) Additions to property, plant, equipment 2,028.7 445.9 818.0 10.7 3,303.3 Total assets at year-end 5,745.7 3,769.8 4,887.1 138.7 14,541.3 Geographic Information Certain Long-Lived Assets at December 31 ( Millions of dollars ) United States Canada Malaysia United Kingdom Other Total 2016 $ 5,121.6 1,451.4 1,637.0 – 106.2 8,316.2 2015 5,484.7 2,310.6 1,912.0 – 111.1 9,818.4 2014 5,419.5 3,574.6 4,258.8 0.4 78.1 13,331.4 Segment Information — Continued ( Millions of dollars ) Corporate and Other Discontinued Operations Consolidated Total Year ended December 31, 2016 Segment loss $ (149.1) (2.0) (276.0) Revenues from external customers 69.5 – 1,874.1 Interest income 2.9 – 2.9 Interest expense, net of capitalization 148.2 – 148.2 Income tax expense (benefit) (64.1) – (219.2) Significant noncash charges (credits) Depreciation, depletion and amortization 16.8 – 1,054.1 Accretion of asset retirement obligations – – 46.7 Amortization of undeveloped leases – – 43.4 Impairment of assets – – 95.1 Deferred and noncurrent income taxes (76.8) – (387.8) Additions to property, plant, equipment 21.9 – 753.1 Total assets at year-end 1,149.9 27.1 10,295.9 Year ended December 31, 2015 Segment loss $ (244.9) (15.0) (2,270.8) Revenues from external customers 98.4 – 3,033.1 Interest income 4.0 – 4.0 Interest expense, net of capitalization 117.4 – 117.4 Income tax expense (benefit) 84.5 – (1,026.5) Significant noncash charges (credits) Depreciation, depletion and amortization 11.9 – 1,619.8 Accretion of asset retirement obligations – – 48.7 Amortization of undeveloped leases – – 75.4 Impairment of assets – – 2,493.2 Deferred and noncurrent income taxes (60.5) – (978.0) Additions to property, plant, equipment 59.9 – 1,791.5 Total assets at year-end 592.2 38.3 11,493.8 Year ended December 31, 2014 Segment income (loss) $ (164.8) (119.4) 905.6 Interest income 7.7 – 7.7 Interest expense, net of capitalization 115.8 – 115.8 Income tax expense (benefit) (58.4) – 227.3 Significant noncash charges (credits) Depreciation, depletion and amortization 8.7 – 1,906.2 Accretion of asset retirement obligations – – 50.8 Amortization of undeveloped leases – – 74.4 Impairment of assets – – 51.3 Deferred and noncurrent income taxes (18.8) – (170.9) Additions to property, plant, equipment 14.5 – 3,317.8 Total assets at year-end 1,773.9 427.1 16,742.3 Geographic Information Revenues from External Customers for the Year ( Millions of dollars ) United States Canada Malaysia Other Total 2016 $ 693.2 421.1 759.3 0.5 1,874.1 2015 1,260.0 557.3 1,210.9 4.9 3,033.1 2014 2,201.5 1,052.4 2,233.0 (10.8) 5,476.1 |
Supplemental Oil and Gas Info52
Supplemental Oil and Gas Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Reserve Quantities [Line Items] | |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | ( Millions of dollars ) United States Canada Malaysia Other Total Year ended December 31, 2016 Property acquisition costs Unproved $ 18.6 – – – 18.6 Proved – 206.7 – – 206.7 Total acquisition costs 18.6 206.7 – – 225.3 Exploration costs* 18.5 3.6 6.0 42.0 70.1 Development costs* 239.7 165.1 102.9 0.3 508.0 Total costs incurred 276.8 375.4 108.9 42.3 803.4 Charged to expense Dry hole expense 0.4 – 4.5 10.2 15.1 Geophysical and other costs 5.7 3.6 0.7 33.4 43.4 Total charged to expense 6.1 3.6 5.2 43.6 58.5 Property additions $ 270.7 371.8 103.7 (1.3) 744.9 Year ended December 31, 2015 Property acquisition costs Unproved $ 10.1 2.5 – – 12.6 Proved – – – – – Total acquisition costs 10.1 2.5 – – 12.6 Exploration costs* 166.8 0.7 69.0 135.4 371.9 Development costs* 1,375.1 231.5 210.0 2.8 1,819.4 Total costs incurred 1,552.0 234.7 279.0 138.2 2,203.9 Charged to expense Dry hole expense 241.3 – 29.7 25.8 296.8 Geophysical and other costs 16.9 0.7 7.9 73.2 98.7 Total charged to expense 258.2 0.7 37.6 99.0 395.5 Property additions $ 1,293.8 234.0 241.4 39.2 1,808.4 Year ended December 31, 2014 Property acquisition costs Unproved $ 92.9 – – – 92.9 Proved 7.4 – – – 7.4 Total acquisition costs 100.3 – – – – 100.3 Exploration costs* 160.0 1.7 6.3 262.1 430.1 Development costs* 1,934.7 413.8 926.6 7.6 3,282.7 Total costs incurred 2,195.0 415.5 932.9 269.7 3,813.1 Charged to expense Dry hole expense 92.1 – 47.4 130.5 270.0 Geophysical and other costs 37.7 1.7 1.3 128.5 169.2 Total charged to expense 129.8 1.7 48.7 259.0 439.2 Property additions $ 2,065.2 413.8 884.2 10.7 3,373.9 * Inclu des non cash asset retirement costs as follows: 2016 Exploration costs $ – – – – – Development costs 0.9 10.5 2.3 – 13.7 $ 0.9 10.5 2.3 – 13.7 2015 Exploration costs $ – – – – – Development costs 30.7 49.1 (3.0) – 76.8 $ 30.7 49.1 (3.0) – 76.8 2014 Exploration costs $ – – – – – Development costs 36.5 (32.1) 66.2 – 70.6 $ 36.5 (32.1) 66.2 – 70.6 |
Results of Operations for Oil andGas Producing Activities | Canada United Conven- ( Millions of dollars ) States tional Synthetic Malaysia Other Total Year ended December 31, 2016 Revenues Crude oil and natural gas liquids sales $ 650.7 171.7 60.7 623.7 – 1,506.8 Natural gas sales 35.1 130.0 – 127.6 292.7 Total oil and gas revenues 685.8 301.7 60.7 751.3 – 1,799.5 Other operating revenues (0.1) (0.7) 3.6 2.1 0.2 5.1 Total revenues 685.7 301.0 64.3 753.4 0.2 1,804.6 Costs and expenses Lease operating expenses 218.6 102.6 69.8 168.4 – 559.4 Severance and ad valorem taxes 37.0 4.3 2.5 – – 43.8 Exploration costs charged to expense 6.1 3.6 – 5.2 43.6 58.5 Undeveloped lease amortization 38.4 4.5 – – 0.5 43.4 Depreciation, depletion and amortization 600.5 186.7 16.5 227.7 5.9 1,037.3 Accretion of asset retirement obligations 17.1 10.9 2.4 16.3 – 46.7 Impairment of assets – 95.1 – – – 95.1 Redetermination expense – – – 39.1 – 39.1 Deepwater rig contract exit benefit (4.3) – – – – (4.3) Selling and general expenses 68.8 28.6 0.5 15.9 33.6 147.4 Other expenses (benefits) (3.2) 7.5 – 23.8 (9.9) 18.2 Total costs and expenses 979.0 443.8 91.7 496.4 73.7 2,084.6 Results of operations before taxes (293.3) (142.8) (27.4) 257.0 (73.5) (280.0) Income tax expense (benefit) (87.9) (58.9) (75.4) 85.9 (18.8) (155.1) Results of operations $ (205.4) (83.9) 48.0 171.1 (54.7) (124.9) Year ended December 31, 2015 Revenues Crude oil and natural gas liquids sales $ 1,176.9 181.0 203.0 790.6 – 2,351.5 Natural gas sales 70.4 167.7 – 185.4 423.5 Total oil and gas revenues 1,247.3 348.7 203.0 976.0 – 2,775.0 Other operating revenues 6.3 (2.4) 0.4 155.4 – 159.7 Total revenues 1,253.6 346.3 203.4 1,131.4 – 2,934.7 Costs and expenses Lease operating expenses 312.0 102.4 166.0 251.9 – 832.3 Severance and ad valorem taxes 55.9 4.8 5.1 – – 65.8 Exploration costs charged to expense 258.2 0.7 – 37.6 99.0 395.5 Undeveloped lease amortization 59.2 14.4 – – 1.8 75.4 Depreciation, depletion and amortization 794.9 211.2 50.7 544.9 6.2 1,607.9 Accretion of asset retirement obligations 20.2 7.2 5.4 15.9 – 48.7 Impairment of assets 329.0 683.6 – 1,480.6 – 2,493.2 Deepwater rig contract exit costs 282.0 – – – – 282.0 Selling and general expenses 88.2 25.5 1.0 5.7 56.8 177.2 Other expense 6.7 43.9 – 15.9 12.1 78.6 Total costs and expenses 2,206.3 1,093.7 228.2 2,352.5 175.9 6,056.6 Results of operations before taxes (952.7) (747.4) (24.8) (1,221.1) (175.9) (3,121.9) Income tax expense (benefit) (337.0) (191.2) 2.4 (567.9) (17.3) (1,111.0) Results of operations $ (615.7) (556.2) (27.2) (653.2) (158.6) (2,010.9) * Results exclude corporate overhead, interest and discontinued operations. Schedule 5 – Results of Operations for Oil and Gas Producing Activities * – Continued Canada United Conven- ( Millions of dollars ) States tional Synthetic Malaysia Other Total Year ended December 31, 2014 Revenues Crude oil and natural gas liquids sales $ 2,062.1 453.3 391.5 1,680.2 – 4,587.1 Natural gas sales 127.2 201.3 – 357.5 – 686.0 Total oil and gas revenues 2,189.3 654.6 391.5 2,037.7 – 5,273.1 Other operating revenues 7.1 (2.4) 0.4 145.8 (1.3) 149.6 Total revenues 2,196.4 652.2 391.9 2,183.5 (1.3) 5,422.7 Costs and expenses Lease operating expenses 345.5 160.3 233.8 350.3 – 1,089.9 Severance and ad valorem taxes 96.5 5.6 5.1 – – 107.2 Exploration costs charged to expense 129.8 1.7 – 48.7 259.0 439.2 Undeveloped lease amortization 50.1 19.4 – – 4.9 74.4 Depreciation, depletion and amortization 840.7 262.7 54.0 735.0 5.1 1,897.5 Accretion of asset retirement obligations 17.5 6.0 9.2 18.1 – 50.8 Impairment of assets 14.3 37.0 – – – 51.3 Selling and general expenses 95.2 26.7 0.9 15.7 73.5 212.0 Other expenses 4.9 1.0 – 16.9 2.1 24.9 Total costs and expenses 1,594.5 520.4 303.0 1,184.7 344.6 3,947.2 Results of operations before taxes 601.9 131.8 88.9 998.8 (345.9) 1,475.5 Income tax expense (benefit) 214.8 42.4 21.8 102.6 (95.9) 285.7 Results of operations $ 387.1 89.4 67.1 896.2 (250.0) 1,189.8 * Results exclude corporate overhead, interest and discontinued operations. |
Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves | ( Millions of dollars ) United States Canada Malaysia Total December 31, 2016 Future cash inflows $ 9,477.9 3,752.7 4,318.7 17,549.3 Future development costs (1,691.1) (1,143.6) (763.8) (3,598.5) Future production costs (3,981.6) (2,329.7) (2,661.2) (8,972.5) Future income taxes (118.9) (81.3) (73.3) (273.5) Future net cash flows 3,686.3 198.1 820.4 4,704.8 10% annual discount for estimated timing of cash flows (1,799.5) (95.0) (230.3) (2,124.8) Standardized measure of discounted future net cash flows $ 1,886.8 103.1 590.1 2,580.0 December 31, 2015 Future cash inflows $ 12,373.9 8,922.0 6,143.1 27,439.0 Future development costs (2,620.5) (1,145.4) (957.8) (4,723.7) Future production costs (4,955.4) (5,892.7) (3,290.5) (14,138.6) Future income taxes (339.7) (504.8) (216.2) (1,060.7) Future net cash flows 4,458.3 1,379.1 1,678.6 7,516.0 10% annual discount for estimated timing of cash flows (2,430.0) (666.8) (560.1) (3,656.9) Standardized measure of discounted future net cash flows $ 2,028.3 712.3 1,118.5 3,859.1 December 31, 2014 Future cash inflows $ 20,767.4 16,257.0 11,909.7 48,934.1 Future development costs (3,151.4) (1,810.5) (1,920.8) (6,882.7) Future production costs (6,378.5) (7,770.2) (4,575.6) (18,724.3) Future income taxes (2,930.1) (1,389.6) (1,249.9) (5,569.6) Future net cash flows 8,307.4 5,286.7 4,163.4 17,757.5 10% annual discount for estimated timing of cash flows (3,729.1) (2,595.3) (1,527.9) (7,852.3) Standardized measure of discounted future net cash flows $ 4,578.3 2,691.4 2,635.5 9,905.2 |
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows | ( Millions of dollars ) 2016 2015 2014 Net changes in prices and production costs $ (1,476.1) (11,365.5) (2,697.8) Net changes in development costs 544.9 591.4 (2,317.3) Sales and transfers of oil and gas produced, net of production costs (1,196.3) (1,876.9) (4,076.0) Net change due to extensions and discoveries 280.5 1,145.8 3,251.6 Net change due to purchases and sales of proved reserves (583.4) (287.4) (1,041.0) Development costs incurred 479.6 1,725.4 3,169.3 Accretion of discount 428.1 1,289.5 1,462.5 Revisions of previous quantity estimates (49.2) 163.3 518.9 Net change in income taxes 292.8 2,568.3 790.3 Net increase (decrease) (1,279.1) (6,046.1) (939.5) Standardized measure at January 1 3,859.1 9,905.2 10,844.7 Standardized measure at December 31 $ 2,580.0 3,859.1 9,905.2 |
Capitalized Costs Relating to Oil and Gas Producing Activities | ( Millions of dollars ) United States Canada Malaysia Other Subtotal Synthetic Oil – Canada Total December 31, 2016 Unproved oil and gas properties $ 360.8 315.6 47.0 125.6 849.0 – 849.0 Proved oil and gas properties 9,384.6 4,241.6 6,147.8 – 19,774.0 – 19,774.0 Gross capitalized costs 9,745.4 4,557.2 6,194.8 125.6 20,623.0 – 20,623.0 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (151.2) (233.6) – (21.8) (406.6) – (406.6) Proved oil and gas properties (4,605.9) (2,877.2) (4,566.6) – (12,049.7) – (12,049.7) Net capitalized costs $ 4,988.3 1,446.4 1,628.2 103.8 8,166.7 – 8,166.7 December 31, 2015 Unproved oil and gas properties $ 570.3 283.1 28.6 128.5 1,010.5 – 1,010.5 Proved oil and gas properties 9,010.0 4,062.2 6,216.0 – 19,288.2 1,174.7 20,462.9 Gross capitalized costs 9,580.3 4,345.3 6,244.6 128.5 20,298.7 1,174.7 21,473.4 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (220.8) (219.4) – (22.4) (462.6) – (462.6) Proved oil and gas properties (4,004.9) (2,586.0) (4,336.9) – (10,927.8) (410.7) (11,338.5) Net capitalized costs $ 5,354.6 1,539.9 1,907.7 106.1 8,908.3 764.0 9,672.3 |
Oil Reserves [Member] | |
Reserve Quantities [Line Items] | |
Summary of Proved Reserves Based on Average Prices | Crude & Synthetic Oil Crude Oil Synthetic Oil ( Millions of barrels ) Total Total United States Canada Malaysia Canada Proved developed and undeveloped crude oil / synthetic oil reserves: December 31, 2013 471.2 354.2 191.5 38.7 124.0 117.0 Revisions of previous estimates (9.3) (2.3) (3.2) 2.7 (1.8) (7.0) Improved recovery 7.5 7.5 – – 7.5 – Extensions and discoveries 42.6 42.6 32.7 2.4 7.5 – Purchases of properties 6.1 6.1 6.1 – – – Sales of properties (24.3) (24.3) (0.3) (0.5) (23.5) – Production (52.0) (47.6) (21.9) (5.9) (19.8) (4.4) December 31, 2014 441.8 336.2 204.9 37.4 93.9 105.6 Revisions of previous estimates 5.3 (8.2) (7.6) (4.8) 4.2 13.5 Improved recovery 2.4 2.4 – – 2.4 – Extensions and discoveries 63.8 63.8 63.8 – – – Sales of properties (11.0) (11.0) – – (11.0) – Production (46.1) (41.8) (22.2) (4.7) (14.9) (4.3) December 31, 2015 456.2 341.4 238.9 27.9 74.6 114.8 Revisions of previous estimates (5.8) (5.8) (10.9) 2.5 2.6 – Extensions and discoveries 11.0 11.0 8.6 – 2.4 – Purchases of properties 26.3 26.3 – 26.3 – – Sales of properties (121.0) (7.8) (4.5) (3.3) – (113.2) Production (37.7) (36.1) (17.7) (4.5) (13.9) (1.6) December 31, 2016 329.0 329.0 214.4 48.9 65.7 – Proved developed crude oil / synthetic oil reserves: December 31, 2013 289.9 172.9 75.8 31.6 65.5 117.0 December 31, 2014 324.1 218.5 106.2 32.4 79.9 105.6 December 31, 2015 326.6 211.8 125.9 23.8 62.1 114.8 December 31, 2016 184.9 184.9 113.9 19.2 51.8 – Proved undeveloped crude oil / synthetic oil reserves: December 31, 2013 181.3 181.3 115.7 7.1 58.5 – December 31, 2014 117.7 117.7 98.7 5.0 14.0 – December 31, 2015 129.6 129.6 113.0 4.1 12.5 – December 31, 2016 144.1 144.1 100.5 29.7 13.9 – |
Natural Gas Liquids Reserves [Member] | |
Reserve Quantities [Line Items] | |
Summary of Proved Reserves Based on Average Prices | ( Millions of barrels ) Total United States Canada Malaysia Proved developed and undeveloped NGL reserves: December 31, 2013 24.4 23.2 0.1 1.1 Revisions of previous estimates 5.1 5.0 – 0.1 Extensions and discoveries 4.7 4.0 0.6 0.1 Sales of properties (0.2) – – (0.2) Production (3.4) (3.1) – (0.3) December 31, 2014 30.6 29.1 0.7 0.8 Revisions of previous estimates 2.0 2.2 (0.3) 0.1 Extensions and discoveries 7.6 7.6 – – Sales of properties (0.1) – – (0.1) Production (3.7) (3.5) – (0.2) December 31, 2015 36.4 35.4 0.4 0.6 Revisions of previous estimates 1.6 1.2 0.2 0.2 Extensions and discoveries 2.9 2.8 0.1 – Purchases of properties 5.1 – 5.1 – Production (3.5) (3.0) (0.2) (0.3) December 31, 2016 42.5 36.4 5.6 0.5 Proved developed NGL reserves: December 31, 2013 14.2 13.1 – 1.1 December 31, 2014 17.5 16.5 0.2 0.8 December 31, 2015 21.6 20.7 0.3 0.6 December 31, 2016 22.2 20.8 0.9 0.5 Proved undeveloped NGL reserves: December 31, 2013 10.2 10.1 0.1 – December 31, 2014 13.1 12.6 0.5 – December 31, 2015 14.8 14.7 0.1 – December 31, 2016 20.3 15.6 4.7 – |
Natural Gas Reserves [Member] | |
Reserve Quantities [Line Items] | |
Summary of Proved Reserves Based on Average Prices | ( Billions of cubic feet ) Total United States Canada Malaysia Proved developed and undeveloped natural gas reserves: December 31, 2013 1,153.6 185.0 562.8 405.8 Revisions of previous estimates 167.2 47.7 105.6 13.9 Improved recovery 7.0 – – 7.0 Extensions and discoveries 696.8 24.1 231.5 441.2 Purchases of properties 5.5 5.5 – – Sales of properties (162.6) (3.7) – (158.9) Production (162.8) (32.3) (57.1) (73.4) December 31, 2014 1,704.7 226.3 842.8 635.6 Revisions of previous estimates 53.5 (5.2) 18.9 39.8 Improved recovery 1.8 – – 1.8 Extensions and discoveries 162.9 43.2 119.7 – Sales of properties (78.0) – – (78.0) Production (156.1) (31.9) (71.8) (52.4) December 31, 2015 1,688.8 232.4 909.6 546.8 Revisions of previous estimates 43.3 0.1 45.3 (2.1) Extensions and discoveries 164.2 6.4 120.2 37.6 Purchases of properties 122.3 – 122.3 – Sales of properties (2.2) (0.1) (2.1) – Production (138.4) (19.4) (76.4) (42.6) December 31, 2016 1,878.0 219.4 1,118.9 539.7 Proved developed natural gas reserves: December 31, 2013 786.2 112.6 384.0 289.6 December 31, 2014 812.1 145.6 467.4 199.1 December 31, 2015 783.5 148.3 453.5 181.7 December 31, 2016 818.1 138.7 498.9 180.5 Proved undeveloped natural gas reserves: December 31, 2013 367.4 72.4 178.8 116.2 December 31, 2014 892.6 80.7 375.4 436.5 December 31, 2015 905.3 84.1 456.1 365.1 December 31, 2016 1,059.9 80.7 620.0 359.2 |
Supplemental Quarterly Informat
Supplemental Quarterly Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Information [Abstract] | |
Schedule of Supplemental Quarterly Information | ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year Year ended December 31, 2016 Sales and other operating revenues $ 429.1 411.2 486.3 483.0 1,809.6 Income (loss) from continuing operations before income taxes (265.0) (131.3) (16.7) (80.1) (493.1) Income (loss) from continuing operations (199.5) 2.9 (14.6) (62.8) (274.0) Net income (loss) (198.8) 2.9 (16.2) (63.9) (276.0) Income (loss) from continuing operations per Common share Basic (1.16) 0.02 (0.08) (0.36) (1.59) Diluted (1.16) 0.02 (0.08) (0.36) (1.59) Net income (loss) per Common share Basic (1.16) 0.02 (0.08) (0.37) (1.60) Diluted (1.16) 0.02 (0.08) (0.37) (1.60) Cash dividend per Common share 0.35 0.35 0.25 0.25 1.20 Market price of Common Stock* High 26.69 36.24 32.66 34.30 36.24 Low 15.76 23.49 25.14 25.00 15.76 Year ended December 31, 2015 Sales and other operating revenues $ 749.2 718.6 665.6 653.7 2,787.1 Income from continuing operations before income taxes (117.7) (110.1) (2,408.0) (646.5) (3,282.3) Income from continuing operations 3.5 (89.0) (1,587.1) (583.2) (2,255.8) Net income (14.5) (73.8) (1,595.4) (587.1) (2,270.8) Income from continuing operations per Common share Basic 0.02 (0.51) (9.22) (3.39) (12.94) Diluted 0.02 (0.51) (9.22) (3.39) (12.94) Net income per Common share Basic (0.08) (0.42) (9.26) (3.41) (13.03) Diluted (0.08) (0.42) (9.26) (3.41) (13.03) Cash dividend per Common share 0.35 0.35 0.35 0.35 1.40 Market price of Common Stock* High 51.77 50.56 41.42 31.03 51.77 Low 43.40 41.42 23.76 21.71 21.71 |
Significant Accounting Polici54
Significant Accounting Policies (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Significant Accounting Policies [Line Items] | ||||||
Maturity of Canadian government securities | 90 days | 90 days | 90 days | |||
Canadian government securities with maturities greater than 90 days at the date of acquisition | $ 111,542,000 | $ 173,288,000 | [1] | |||
Impairment of assets | $ 95,088,000 | 2,493,156,000 | $ 51,314,000 | |||
Goodwill | $ 0 | 0 | ||||
Stock Options [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Stock-based compensation, fair value assumption model | Black-Scholes option pricing model | |||||
Performance Based Restricted Stock [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Stock-based compensation, fair value assumption model | Monte Carlo valuation model | |||||
Stock-based compensation, vesting period | 3 years | |||||
Minimum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Equity method investment, ownership percentage | 20.00% | |||||
Minimum [Member] | Stock Options [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Stock-based compensation, vesting period | 2 years | |||||
Maximum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Equity method investment, ownership percentage | 50.00% | |||||
Maximum [Member] | Stock Options [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Stock-based compensation, vesting period | 3 years | |||||
Natural Gas Processing Facilities [Member] | Minimum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Depreciable lives, straight-line method | 20 years | |||||
Natural Gas Processing Facilities [Member] | Maximum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Depreciable lives, straight-line method | 25 years | |||||
Syncrude [Member] | Minimum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Turnarounds for major processing units | 2 years | |||||
Syncrude [Member] | Maximum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Turnarounds for major processing units | 3 years | |||||
Canada [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Impairment of assets | $ 37,047,000 | $ 95,088,000 | $ 683,574,000 | $ 37,047,000 | [2] | |
[1] | Reclassified to conform to current presentation. See Note B for additional information. | |||||
[2] | This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. |
New Accounting Principles and55
New Accounting Principles and Recent Accounting Pronouncements (Narrative) (Details) - Accounting Standards Update 2015-17 [Member] $ in Millions | Dec. 31, 2015USD ($) |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Current deferred tax assets | $ (51.2) |
Noncurrent deferred tax assets | $ 51.2 |
Discontinued Operations and A56
Discontinued Operations and Assets Held for Sale (Narrative) (Details) - USD ($) | Sep. 30, 2014 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||
Proceeds from sales of property, plant and equipment | $ 1,155,144,000 | $ 423,911,000 | $ 1,467,046,000 | ||
Impairment of assets | $ 95,088,000 | 2,493,156,000 | 51,314,000 | ||
Gain on disposal | $ (4,990,000) | 101,684,000 | |||
UK Refining And Marketing Operations [Member] | |||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||
Proceeds from sales of property, plant and equipment | $ 211,965,000 | $ 5,500,000 | |||
Impairment of assets | 269,200,000 | ||||
Effect of LIFO Inventory Liquidation on Income | 209,600,000 | ||||
Gain on disposal | $ 101,700,000 |
Discontinued Operations and A57
Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Accounts receivable | $ 357,099 | $ 522,672 | [1] | |
Total current assets held for sale | 27,070 | 38,340 | [1] | |
Accounts payable | 784,975 | 1,529,848 | [1] | |
Total current liabilities associated with assets held for sale | 2,776 | 7,297 | [1] | |
Asset retirement obligation - Seal asset | 681,528 | 793,474 | [1] | |
Total non-current liabilities associated with assets held for sale | [2] | 85,900 | ||
Discontinued Operations [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Cash | 4,126 | 7,927 | ||
Accounts receivable | 22,944 | 29,358 | ||
Other | 1,055 | |||
Total current assets held for sale | 27,070 | 38,340 | ||
Accounts payable | 270 | 2,433 | ||
Accrued compensation and severance | 2,179 | |||
Refinery decommissioning cost | 2,506 | 2,685 | ||
Total current liabilities associated with assets held for sale | 2,776 | $ 7,297 | ||
Asset retirement obligation - Seal asset | 85,900 | |||
Total non-current liabilities associated with assets held for sale | $ 85,900 | |||
[1] | Reclassified to conform to current presentation. See Note B for additional information. | |||
[2] | Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. |
Discontinued Operations and A58
Discontinued Operations and Assets Held for Sale (Results of Operations Associated with Discontinued Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Discontinued Operations and Assets Held for Sale [Abstract] | |||
Revenues | $ 381,747 | $ 2,786,394 | |
Loss from operations before income taxes | $ (2,027) | (6,758) | (261,873) |
Gain (loss) on sale before income taxes | (4,990) | 101,684 | |
Total loss from discontinued operations before taxes | (2,027) | (11,748) | (160,189) |
Income tax expense (benefit) | 3,313 | (40,827) | |
Loss from discontinued operations | $ (2,027) | $ (15,061) | $ (119,362) |
Inventories (Schedule of Invent
Inventories (Schedule of Inventory) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Inventories [Abstract] | |||
Unsold crude oil | $ 17,146 | $ 25,583 | |
Materials and supplies | 109,925 | 141,205 | |
Inventory, Net, Total | $ 127,071 | $ 166,788 | [1] |
[1] | Reclassified to conform to current presentation. See Note B for additional information. |
Property, Plant and Equipment60
Property, Plant and Equipment (Narrative) (Details) - USD ($) | Sep. 30, 2014 | Jan. 31, 2015 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property Plant And Equipment [Line Items] | ||||||||
Proceeds from sales of property, plant and equipment | $ 1,155,144,000 | $ 423,911,000 | $ 1,467,046,000 | |||||
Cost of acquired assets | 225,300,000 | 12,600,000 | 100,300,000 | |||||
Impairment of assets | 95,088,000 | 2,493,156,000 | 51,314,000 | |||||
Total capitalized exploratory well costs | 148,500,000 | 130,514,000 | 120,455,000 | $ 393,030,000 | ||||
Redetermination expense | [1] | 39,100,000 | ||||||
Exploratory well costs capitalized more than one year | $ 128,019,000 | |||||||
UK Refining And Marketing Operations [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Proceeds from sales of property, plant and equipment | $ 211,965,000 | $ 5,500,000 | ||||||
Impairment of assets | $ 269,200,000 | |||||||
Syncrude Canada Ltd. [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Percentage of interest in oil and gas property sold during period | 5.00% | |||||||
Gain (loss) on sale of assets, net of taxes | $ 71,700,000 | |||||||
Montney Natural Gas Fields [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Proceeds from sales of property, plant and equipment | 414,100,000 | |||||||
Deferred gain on sale of property | $ 187,000,000 | |||||||
Deferred gain, period of recognition | 20 years | |||||||
Deferred gain, accumulated amortization | $ 5,108,000 | |||||||
Brunei [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Exploratory well costs capitalized more than one year | $ 64,492,000 | |||||||
Kaybob Duvernay Lands, Alberta [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Interest in assets acquired | 70.00% | |||||||
Montney Lands, Alberta [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Interest in assets acquired | 30.00% | |||||||
Kakap Field, Block K, Malaysia [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Working interest | 8.60% | |||||||
Malaysia [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Percentage of interest in oil and gas property sold during period | 10.00% | 20.00% | ||||||
Proceeds from sales of property, plant and equipment | $ 417,200,000 | $ 1,460,425,000 | ||||||
Gain (loss) on sale of assets, net of taxes | 218,800,000 | 321,454,000 | ||||||
Impairment of assets | [1] | 1,480,600,000 | ||||||
Redetermination expense | [1] | $ 39,100,000 | ||||||
Exploratory well costs capitalized more than one year | 63,527,000 | |||||||
Gulf Of Mexico [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Impairment of assets | 328,982,000 | 14,267,000 | ||||||
Parent Company [Member] | Syncrude Canada Ltd. [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Proceeds from sales of property, plant and equipment | 739,100,000 | |||||||
Parent Company [Member] | Montney Lands, Alberta [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Cost of acquired assets, cash paid | 206,700,000 | |||||||
Athabasca Oil Corporation [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Cost of acquired assets, carried interest | $ 168,000,000 | |||||||
Cost of acquired assets, interest carry period | 5 years | |||||||
Athabasca Oil Corporation [Member] | Subsidiary [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Cost of acquired assets | $ 375,000,000 | |||||||
Zero to One Year [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Total capitalized exploratory well costs | 20,481,000 | 66,032,000 | ||||||
One to Two Years [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Total capitalized exploratory well costs | 63,527,000 | 59,330,000 | ||||||
Two to Three Years [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Total capitalized exploratory well costs | 57,876,000 | 6,606,000 | ||||||
Three Years or More [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Total capitalized exploratory well costs | $ 64,492,000 | $ 6,606,000 | $ 54,519,000 | |||||
[1] | Results exclude corporate overhead, interest and discontinued operations. |
Property, Plant and Equipment61
Property, Plant and Equipment (Schedule of Recognized Impairments) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Property Plant And Equipment [Line Items] | ||||||
Impairment Expense | $ 95,088,000 | $ 2,493,156,000 | $ 51,314,000 | |||
Gulf Of Mexico [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Impairment Expense | 328,982,000 | 14,267,000 | ||||
Canada [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Impairment Expense | $ 37,047,000 | 95,088,000 | 683,574,000 | 37,047,000 | [1] | |
Malaysia [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Impairment Expense | [2] | 1,480,600,000 | ||||
Conventional [Member] | Canada [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Impairment Expense | [2] | $ 95,100,000 | $ 683,600,000 | $ 37,000,000 | ||
[1] | This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. | |||||
[2] | Results exclude corporate overhead, interest and discontinued operations. |
Property, Plant and Equipment62
Property, Plant and Equipment (Schedule of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | ||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment, Cost | $ 20,924,003 | $ 21,742,558 | ||
Property, plant and equipment, Net | 8,316,188 | 9,818,365 | [1] | |
Exploration and Production [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment, Cost | [2] | 20,767,772 | 21,607,962 | |
Property, plant and equipment, Net | [2],[3] | 8,214,740 | 9,723,222 | |
Corporate and Other [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment, Cost | 156,231 | 134,596 | ||
Property, plant and equipment, Net | 101,448 | 95,143 | ||
Mineral Rights [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment, Cost | 595,138 | 1,075,040 | ||
Property, plant and equipment, Net | 188,689 | 612,518 | ||
Administrative Assets and Support Equipment [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment, Net | $ 48,053 | $ 50,924 | ||
[1] | Reclassified to conform to current presentation. See Note B for additional information. | |||
[2] | Includes mineral rights as follows: $595,138 188,689 1,075,040 612,518 | |||
[3] | Includes $48,053 in 2016 and $50,924 in 2015 related to administrative assets and support equipment. |
Property, Plant And Equipment63
Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant And Equipment [Abstract] | |||
Beginning balance at January 1 | $ 130,514,000 | $ 120,455,000 | $ 393,030,000 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 17,986,000 | 64,578,000 | 2,874,000 |
Reclassifications to proved properties based on the determination of proved reserves | (91,236,000) | ||
Reduction of capitalized exploratory well costs due to partial asset sale in Malaysia | (122,175,000) | ||
Capitalized exploratory well costs charged to expense | (54,519,000) | (62,038,000) | |
Balance at December 31 | $ 148,500,000 | $ 130,514,000 | $ 120,455,000 |
Property, Plant And Equipment64
Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) | 12 Months Ended | |||
Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($)item | Dec. 31, 2013USD ($) | |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Amount | $ | $ 148,500,000 | $ 130,514,000 | $ 120,455,000 | $ 393,030,000 |
No. of Wells | 12 | 13 | 8 | |
No. of Projects | 6 | 6 | 3 | |
Zero to One Year [Member] | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Amount | $ | $ 20,481,000 | $ 66,032,000 | ||
No. of Wells | 1 | 7 | ||
No. of Projects | 1 | 6 | ||
One to Two Years [Member] | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Amount | $ | $ 63,527,000 | $ 59,330,000 | ||
No. of Wells | 5 | 3 | ||
No. of Projects | 5 | 1 | ||
Two to Three Years [Member] | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Amount | $ | $ 57,876,000 | $ 6,606,000 | ||
No. of Wells | 3 | 3 | ||
Three Years or More [Member] | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Amount | $ | $ 64,492,000 | $ 6,606,000 | $ 54,519,000 | |
No. of Wells | 6 | 3 | 2 | |
No. of Projects | 2 |
Financing Arrangements (Narrati
Financing Arrangements (Narrative) (Details) - USD ($) | Mar. 31, 2017 | Aug. 31, 2016 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 21, 2016 | Sep. 30, 2016 |
Line of Credit Facility [Line Items] | ||||||
Issue cost of debt facility | $ 14,085,000 | |||||
Capital lease payment duration | 15 years | |||||
Capital lease expiration date | Mar. 1, 2029 | |||||
Capital lease obligations, current | $ 20,617,000 | |||||
Capital lease obligations, noncurrent | $ 195,785,000 | |||||
6.875% Notes Due August 15, 2024 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Face amount of notes | $ 550,000,000 | |||||
Notes payable, stated interest rate | 6.875% | 6.875% | ||||
Maturity date | Aug. 15, 2024 | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility maximum borrowing capacity | $ 1,200,000,000 | |||||
Credit facility, maturity date | Aug. 1, 2019 | |||||
Line of credit facility fee | 0.50% | |||||
Issue cost of debt facility | $ 14,000,000 | |||||
Amount outstanding | $ 0 | |||||
Minumum borrowing capacity through automatic reductions | $ 1,000,000,000 | |||||
Minimum adjusted EBITDAX to consolidated interest expense | 250.00% | |||||
Maximum consolidated debt to maximum adjusted EBITDAX | 375.00% | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | United States And Canada [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Minimum liquidity | $ 500,000,000 | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Scenario, Forecast [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Maximum leverage ratio | 325.00% | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Minimum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility interest rate above LIBOR | 2.50% | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Maximum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility interest rate above LIBOR | 4.50% | |||||
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Letter of Credit [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Amount outstanding | $ 88,000,000 | |||||
Amended 2016 Senior Unsecured Guaranteed Credity Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Threshold of outstanding borrowings on facility that triggers guarantee obligation by subsidiary | $ 500,000,000 | |||||
Threshold of debt to EBITDAX that triggers guarantee obligation by subsidiary | 425.00% | |||||
Amended 2016 Senior Unsecured Guaranteed Credity Facility [Member] | Scenario, Forecast [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility maximum borrowing capacity | $ 1,100,000,000 | |||||
Threshold of debt to EBITDAX that triggers guarantee obligation by subsidiary | 400.00% | |||||
2011 Unscured Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility maximum borrowing capacity | $ 2,000,000,000 | $ 630,000,000 | ||||
Credit facility, maturity date | Jun. 1, 2017 | |||||
Amount outstanding | $ 0 | |||||
Credit facility interest rate above LIBOR | 1.45% | |||||
Maximum total debt to total capital employed | 60.00% |
Long term Debt (Narrative) (Det
Long term Debt (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Financing Arrangements [Abstract] | |
Future maturities of long term debt in 2017 | $ 569,817,000 |
Future maturities of long term debt in 2018 | 13,554,000 |
Future maturities of long term debt in 2019 | 14,233,000 |
Future maturities of long term debt in 2020 | 14,988,000 |
Future maturities of long term debt in 2021 | 15,697,000 |
Thereafter | $ 2,364,278,000 |
Capital lease duration | 25 years |
Long term Debt (Schedule of Lon
Long term Debt (Schedule of Long Term Debt) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Aug. 31, 2016 | Dec. 31, 2015 | |||
Debt Instrument [Line Items] | |||||
Notes payable | $ 2,800,000 | $ 2,850,000 | |||
Unamortized discount on notes payable | (23,835) | (19,223) | |||
Total notes payable, net of unamortized discount | 2,776,165 | 2,830,777 | |||
Capitalized lease obligation, due through June 2029 | 216,402 | 228,698 | |||
Total debt including current maturities | 2,992,567 | 3,059,475 | |||
Current maturities | (569,817) | (18,881) | [1] | ||
Total long-term debt | $ 2,422,750 | 3,040,594 | [1] | ||
Capital lease expiration date | Mar. 1, 2029 | ||||
2.50% notes, due December 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | [2] | $ 550,000 | $ 550,000 | ||
Notes payable, stated interest rate | [2] | 2.50% | 2.50% | ||
Notes payable, due date | [2] | December 2,017 | |||
Interest rate increase | 1.00% | ||||
4.00% notes, due June 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | $ 500,000 | $ 500,000 | |||
Notes payable, stated interest rate | 4.00% | ||||
Notes payable, due date | June 2,022 | ||||
3.70% notes, due December 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | [2] | $ 600,000 | $ 600,000 | ||
Notes payable, stated interest rate | [2] | 3.70% | 3.70% | ||
Notes payable, due date | [2] | December 2,022 | |||
Interest rate increase | 1.00% | ||||
6.875% Notes Due August 15, 2024 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | $ 550,000 | ||||
Notes payable, stated interest rate | 6.875% | 6.875% | |||
Maturity date | Aug. 15, 2024 | ||||
7.05% notes, due May 2029 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | $ 250,000 | $ 250,000 | |||
Notes payable, stated interest rate | 7.05% | 7.05% | |||
Notes payable, due date | May 2,029 | ||||
5.125% notes, due December 2042 [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | [2] | $ 350,000 | $ 350,000 | ||
Notes payable, stated interest rate | [2] | 5.125% | 5.125% | ||
Notes payable, due date | [2] | December 2,042 | |||
Notes payable to banks, 1.4375% [Member] | |||||
Debt Instrument [Line Items] | |||||
Notes payable | $ 600,000 | ||||
Notes payable, stated interest rate | 1.4375% | ||||
[1] | Reclassified to conform to current presentation. See Note B for additional information. | ||||
[2] | The interest rate paid is 1.0% above rate shown due to a downgrade of the credit rating for the Company's notes in February 2016. |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | |||
Asset Retirement Obligations [Abstract] | |||||||
Balance at beginning of year | $ 825,312 | $ 875,728 | |||||
Accretion expense | 46,742 | 48,665 | $ 50,778 | ||||
Liabilities incurred | 13,690 | 76,775 | |||||
Revision of previous estimates | (4,511) | (85,504) | |||||
Liabilities settled | (20,589) | (13,359) | |||||
Liabilities assumed by purchaser of oil and gas assets | (91,883) | (33,448) | |||||
Changes due to translation of foreign currencies | 12,296 | (43,545) | |||||
Balance at end of year | $ 825,312 | $ 875,728 | $ 875,728 | $ 781,057 | $ 825,312 | ||
Liabilities reported as held for sale at end of year | [1] | (85,900) | |||||
Current portion of liability at end of year | [2] | (13,629) | (31,838) | ||||
Noncurrent portion of liability at end of year | $ 681,528 | $ 793,474 | [3] | ||||
[1] | Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. | ||||||
[2] | Included in Other Accrued Liabilities on the Consolidated Balance Sheet. | ||||||
[3] | Reclassified to conform to current presentation. See Note B for additional information. |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Examination [Line Items] | ||||
Income tax expense (benefit) | $ (219,172,000) | $ (1,026,490,000) | $ 227,297,000 | |
Increase (decrease) in deferred tax asset valuation allowance | 10,983,000 | |||
Deferred tax asset. operating loss carryforward | $ 454,231,000 | |||
Operating loss carryforward, expiration date | Dec. 31, 2036 | |||
Undistributed earnings of subsidiaries considered indefinitely invested | $ 3,000,000,000 | |||
Unrecognized deferred tax liability | $ 395,000,000 | |||
Withholding tax on any monies repatriated from Canada to the U.S. | 5.00% | |||
Other recorded liabilities for interest and penalties | $ 233,000 | $ 343,000 | 233,000 | 142,000 |
Income tax expense, (charges) net benefits for interest and penalties | 111,000 | 91,000 | $ 4,000 | |
United States [Member] | ||||
Income Tax Examination [Line Items] | ||||
Operating loss carryforwards | $ (1,290,000,000) | |||
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions | 2,011 | |||
Canada [Member] | ||||
Income Tax Examination [Line Items] | ||||
Unrecognized deferred tax liability | $ 0 | |||
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions | 2,008 | |||
Malaysia [Member] | ||||
Income Tax Examination [Line Items] | ||||
Unrecognized deferred tax liability | $ 0 | |||
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions | 2,009 | |||
United Kingdom [Member] | ||||
Income Tax Examination [Line Items] | ||||
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions | 2,014 | |||
Minimum [Member] | ||||
Income Tax Examination [Line Items] | ||||
Expected liability to be added for uncertain taxes during next twelve months | $ 1,000,000 | |||
Maximum [Member] | ||||
Income Tax Examination [Line Items] | ||||
Expected liability to be added for uncertain taxes during next twelve months | $ 2,000,000 | |||
Subsidiary [Member] | ||||
Income Tax Examination [Line Items] | ||||
Dividend payable to parent company | 2,000,000,000 | |||
Cash dividend paid to parent | 800,000,000 | |||
Note payable, parent | 1,200,000,000 | 1,200,000,000 | ||
Income tax expense (benefit) | 188,461,000 | |||
Note payable | $ 1,200,000,000 | $ 1,200,000,000 | ||
Foreign Country [Member] | Minimum [Member] | ||||
Income Tax Examination [Line Items] | ||||
Foreign tax credit carryforwards expiration year | 2,017 | |||
Foreign Country [Member] | Maximum [Member] | ||||
Income Tax Examination [Line Items] | ||||
Foreign tax credit carryforwards expiration year | 2,026 |
Income Taxes (Components of Inc
Income Taxes (Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income (loss) from continuing operations before income taxes | |||||||||||
United States | $ (595,196) | $ (1,259,268) | $ 179,484 | ||||||||
Foreign | 102,081 | (2,022,994) | 1,072,786 | ||||||||
Income (loss) from continuing operations before income taxes | $ (80,100) | $ (16,700) | $ (131,300) | $ (265,000) | $ (646,500) | $ (2,408,000) | $ (110,100) | $ (117,700) | (493,115) | (3,282,262) | 1,252,270 |
Income tax expense (benefit) | |||||||||||
Federal - Current | (9,435) | 25,151 | |||||||||
Federal - Deferred | (197,450) | (241,127) | 25,444 | ||||||||
Total Federal income tax expense (benefit) | (197,450) | (250,562) | 50,595 | ||||||||
State | 13,984 | (5,294) | 8,840 | ||||||||
Foreign - Current | 146,861 | (40,550) | 359,502 | ||||||||
Foreign - Deferred | (182,567) | (730,084) | (191,640) | ||||||||
Total Foreign income tax expense (benefit) | (35,706) | (770,634) | 167,862 | ||||||||
Total income tax expense (benefit) | $ (219,172) | $ (1,026,490) | $ 227,297 |
Income Taxes (Effective Income
Income Taxes (Effective Income Tax Rates) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income tax expense (benefit) based on the U.S. statutory tax rate | $ (172,590) | $ (1,148,792) | $ 438,295 |
Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate | 8,582 | 49,739 | 20,562 |
State income taxes, net of federal benefit | 9,090 | (3,441) | 5,746 |
U.S. tax benefit on certain foreign upstream investments | (21,336) | (16,939) | (95,838) |
Current tax in distribution of foreign earnings | 52,724 | ||
Deferred tax on distribution of foreign earnings | 188,461 | ||
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures | 25,734 | 40,788 | 37,712 |
Other, net | 18,741 | (13,747) | (4,663) |
Total income tax expense (benefit) | (219,172) | (1,026,490) | 227,297 |
Canada [Member] | |||
Tax effects on sale of assets | (89,473) | ||
Malaysia [Member] | |||
Tax effects on sale of assets | $ 2,080 | $ (122,559) | $ (227,241) |
Income Taxes (Analysis of Defer
Income Taxes (Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred tax assets | ||
Property and leasehold costs | $ 572,481 | $ 587,517 |
Liabilities for dismantlements | 170,946 | 114,565 |
Postretirement and other employee benefits | 214,288 | 226,217 |
Alternative minimum tax | 29,710 | 39,683 |
Foreign tax credit carryforwards | 33,295 | 855 |
U.S. net operating loss | 454,231 | |
Other deferred tax assets | 16,541 | 127,165 |
Total gross deferred tax assets | 1,491,492 | 1,096,002 |
Less valuation allowance | (305,389) | (294,406) |
Net deferred tax assets | 1,186,103 | 801,596 |
Deferred tax liabilities | ||
Accumulated depreciation, depletion and amortization | (867,343) | (793,972) |
Other deferred tax liabilities | (21,908) | (21,095) |
Total gross deferred tax liabilities | (889,251) | (815,067) |
Net deferred tax assets (liabilities) | $ 296,852 | $ (13,471) |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Abstract] | |||
Balance at January 1 | $ 6,631 | $ 6,011 | $ 6,366 |
Additions for tax positions related to current year | 756 | 821 | 988 |
Settlements due to lapse of time | (1,225) | ||
Foreign currency translation effect | 30 | (201) | (118) |
Balance at December 31 | $ 7,417 | $ 6,631 | $ 6,011 |
Incentive Plans (Narrative) (De
Incentive Plans (Narrative) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Unvested share-based compensation arrangements, compensation costs to be expensed | $ 28,458,000 | |||
Unvested share-based compensation arrangements, number of years compensation costs to be expensed | 2 years | |||
Income tax benefits realized option exercises | $ 0 | $ 36,000 | $ 5,364,000 | |
Vesting scheme | Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. | |||
Total intrinsic value of options exercised | $ 0 | $ 221,000 | $ 12,003,000 | |
Stock options exercised | [1] | 15,575 | 119,994 | |
Share based compensation settled in cash | $ 17,181,000 | $ 1,594,000 | $ 9,667,000 | |
Incentive compensation plan expense | $ 25,800,000 | $ 26,393,000 | $ 38,000,000 | |
Share-based Compensation Award, Tranche One [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 2 years | |||
Share-based Compensation Award, Tranche Two [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Maximum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Option term | 7 years | |||
2012 Long-Term Plan [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Long term plan expiration year | 2,022 | |||
Maximum number of shares available for issuance | 8,700,000 | |||
Maximum number of shares available for issuance, annual rate | 1.00% | |||
Number of shares available | 3,000,000 | |||
Employee Stock Purchase Plan [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Salary that can be withheld by eligible employee for stock purchase | 10.00% | |||
Stock purchase price, percentage of the fair value of the stock | 90.00% | |||
Employee Stock purchase plan, termination date | The ESPP will terminate on the earlier of the date that employees have purchased all 980,000 authorized shares or June 30, 2017. | |||
Employee stock purchases, shares | 8,962 | 8,387 | 6,739 | |
Employee stock purchases, price per share | $ 23.41 | $ 34.93 | $ 56.22 | |
Number of shares available | 262,853 | |||
Compensation costs estimation | Compensation costs related to the ESPP are estimated based on the value of the 10% discount and the fair value of the option that provides for the refund of participant withholdings | |||
Discount percentage | 10.00% | |||
Compensation expenses | $ 41,000 | $ 29,000 | $ 55,000 | |
Fair value per share issued under ESPP | $ 2.94 | $ 5.74 | $ 6.49 | |
Employee Stock Purchase Plan [Member] | Maximum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Maximum number of shares available for issuance | 980,000 | |||
2012 Long-Term Plan and the 2007 Long-Term Plan [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Option granted to date, term of years | 7 years | |||
2012 Long-Term Plan and the 2007 Long-Term Plan [Member] | Share-based Compensation Award, Tranche One [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting percentage | 50.00% | |||
Stock Options [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Exercise price of options granted | $ 17.57 | $ 49.67 | $ 55.82 | |
Granted stock options, valuation per option | $ 5.03 | |||
Stock-based compensation, fair value assumption model | Black-Scholes option pricing model | |||
Stock options exercised | 32,349 | 862,407 | ||
Stock Options [Member] | Minimum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Granted stock options, valuation per option | $ 10.97 | $ 12.84 | ||
Vesting period | 2 years | |||
Stock Options [Member] | Maximum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Granted stock options, valuation per option | 11.08 | |||
Vesting period | 3 years | |||
Time-Lapse Restricted Stock and Restricted Stock Units [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value per share at grant date | $ 17.57 | 49.67 | ||
Time-Lapse Restricted Stock and Restricted Stock Units [Member] | Minimum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value per share at grant date | 55.20 | |||
Time-Lapse Restricted Stock and Restricted Stock Units [Member] | Maximum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value per share at grant date | 60.85 | |||
Performance Based Restricted Stock [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Stock-based compensation, fair value assumption model | Monte Carlo valuation model | |||
Performance Based Restricted Stock [Member] | Minimum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value per share at grant date | $ 12.21 | 44.03 | 33.90 | |
Performance Based Restricted Stock [Member] | Maximum [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Fair value per share at grant date | $ 16.34 | $ 48.12 | $ 51.30 | |
[1] | Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares. |
Incentive Plans (Share-Based Pl
Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Incentive Plans [Abstract] | |||
Compensation charged against income (loss) before income tax benefit | $ 46,300 | $ 44,021 | $ 53,157 |
Related income tax benefit recognized in income | $ 15,244 | $ 13,583 | $ 15,604 |
Incentive Plans (Fair Value of
Incentive Plans (Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model) (Details) - Stock Options [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items] | |||
Fair value per option grant | $ 5.03 | ||
Assumptions | |||
Dividend yield | 4.00% | ||
Expected volatility | 45.00% | ||
Risk-free interest rate | 1.32% | ||
Expected life | 5 years 2 months 12 days | 5 years 3 months 18 days | 5 years 4 months 6 days |
Minimum [Member] | |||
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items] | |||
Fair value per option grant | $ 10.97 | $ 12.84 | |
Assumptions | |||
Dividend yield | 2.40% | 2.00% | |
Expected volatility | 29.00% | 29.00% | |
Risk-free interest rate | 1.34% | 1.62% | |
Maximum [Member] | |||
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items] | |||
Fair value per option grant | $ 11.08 | ||
Assumptions | |||
Dividend yield | 2.50% | ||
Expected volatility | 30.00% | ||
Risk-free interest rate | 1.60% |
Incentive Plans (Changes in Sto
Incentive Plans (Changes in Stock Options Outstanding) (Details) - $ / shares | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Number of Shares | |||||
Exercised | [1] | (15,575) | (119,994) | ||
Outstanding at end of year | 5,757,435 | ||||
Exercisable at end of year | 3,830,535 | ||||
Stock Options [Member] | |||||
Number of Shares | |||||
Outstanding at beginning of year | 5,443,288 | 5,602,250 | 6,006,585 | ||
Granted at FMV | 862,000 | 991,000 | 772,900 | ||
Exercised | (32,349) | (862,407) | |||
Forfeited | (547,853) | (1,117,613) | (314,828) | ||
Outstanding at end of year | 5,757,435 | 5,443,288 | 5,602,250 | ||
Exercisable at end of year | 3,830,535 | 3,542,352 | 3,030,105 | 2,435,322 | |
Average Exercise Price | |||||
Outstanding at beginning of year | $ 52.93 | $ 57.95 | $ 56.80 | ||
Granted at FMV | 17.57 | 49.67 | 55.82 | ||
Exercised | 40.80 | 49.27 | |||
Forfeited | 44.23 | 31.99 | 54.53 | ||
Outstanding at end of year | 48.46 | 52.93 | 57.95 | ||
Exercisable at end of year | $ 53.80 | $ 52.26 | $ 53.10 | $ 51.79 | |
[1] | Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares. |
Incentive Plans (Additional Inf
Incentive Plans (Additional Information about Stock Options Outstanding) (Details) | 12 Months Ended |
Dec. 31, 2016USD ($)$ / sharesshares | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Options Outstanding | 5,757,435 |
Options Outstanding, Avg. Life Remaining in Years | 3 years 2 months 12 days |
Options Outstanding, Aggregate Intrinsic Value | $ | $ 11,354,000 |
Options Exercisable | 3,830,535 |
Options Exercisable, Avg. Life Remaining in Years | 2 years |
Range of Exercise Prices per Option $17.57 to $39.02 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of exercise prices, lower limit | $ / shares | $ 17.57 |
Range of exercise prices, upper limit | $ / shares | $ 39.02 |
Options Outstanding | 892,350 |
Options Outstanding, Avg. Life Remaining in Years | 5 years 10 months 24 days |
Options Outstanding, Aggregate Intrinsic Value | $ | $ 11,354,000 |
Options Exercisable | 55,350 |
Options Exercisable, Avg. Life Remaining in Years | 2 years 6 months |
Range of Exercise Prices per Option $45.48 to $51.63 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of exercise prices, lower limit | $ / shares | $ 45.48 |
Range of exercise prices, upper limit | $ / shares | $ 51.63 |
Options Outstanding | 2,379,926 |
Options Outstanding, Avg. Life Remaining in Years | 2 years 9 months 18 days |
Options Exercisable | 1,556,926 |
Options Exercisable, Avg. Life Remaining in Years | 1 year 7 months 6 days |
Range of Exercise Prices per Option $54.21 to $62.98 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of exercise prices, lower limit | $ / shares | $ 54.21 |
Range of exercise prices, upper limit | $ / shares | $ 62.98 |
Options Outstanding | 2,485,159 |
Options Outstanding, Avg. Life Remaining in Years | 2 years 7 months 6 days |
Options Exercisable | 2,218,259 |
Options Exercisable, Avg. Life Remaining in Years | 2 years 4 months 24 days |
Incentive Plans (Changes in Per
Incentive Plans (Changes in Performance-Based RSU Outstanding) (Details) - Equity-Settled Restricted Stock Units [Member] - shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Balance at beginning of year | 1,103,986 | 1,397,040 | 1,560,292 |
Granted | 394,000 | 455,000 | 464,300 |
Awarded | (361,096) | (521,800) | (473,186) |
Forfeited | (144,317) | (226,254) | (154,366) |
Balance at end of year | 992,573 | 1,103,986 | 1,397,040 |
Incentive Plans (Assumptions us
Incentive Plans (Assumptions used in Valuation Performance Awards Granted) (Details) - Performance Based Restricted Stock [Member] | 12 Months Ended | ||
Dec. 31, 2016item$ / shares | Dec. 31, 2015item$ / shares | Dec. 31, 2014item$ / shares | |
Assumptions | |||
Expected volatility | 33.00% | 26.00% | 29.00% |
Risk-free interest rate | 0.93% | 0.85% | 0.65% |
Stock beta | item | 0.863 | 0.813 | 0.843 |
Expected life | 3 years | 3 years | 3 years |
Minimum [Member] | |||
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items] | |||
Fair value per share at grant date | $ 12.21 | $ 44.03 | $ 33.90 |
Maximum [Member] | |||
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items] | |||
Fair value per share at grant date | $ 16.34 | $ 48.12 | $ 51.30 |
Incentive Plans (Changes in Tim
Incentive Plans (Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding) (Details) - Restricted Stock and Restricted Stock Units [Member] - shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Share based Compensation Arrangements by Share based Payment Award, Equity Instruments, Other Than Options, Restricted Stock Units [Line Items] | |||
Balance at beginning of year | 477,244 | 321,789 | 112,881 |
Granted | 503,555 | 282,065 | 278,892 |
Vested and issued | (32,092) | (69,610) | (54,884) |
Forfeited | (25,425) | (57,000) | (15,100) |
Balance at end of year | 923,282 | 477,244 | 321,789 |
Employee and Retiree Benefit 82
Employee and Retiree Benefit Plans (Narrative) (Details) - USD ($) | 12 Months Ended | 120 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | |
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Future annual rate of increase in cost of health care for 2016 to measure postretirement benefit obligations | 7.20% | |||
Ultimate rate of health care cost in 2028 and thereafter | 4.50% | |||
Equity securities minimum market capitalization | $ 100,000,000 | $ 100,000,000 | ||
Weighted average expected return on plan asset | 5.62% | |||
Basis used to determine expected return on plan asset, average expected investment expenses | 0.60% | |||
Perentage return on plan assets | 5.69% | |||
Defined benefit plan, percentage of employer's matching contribution | 6.00% | |||
Thrift plan expense | $ 7,395,000 | $ 7,607,000 | $ 10,229,000 | |
Investment 2 [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Domestic plan, investment notice period | 90 days | |||
Investment 3 [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Domestic plan, investment lock up period | 3 years | |||
Domestic plan, investment notice period | 95 days | |||
Foreign Other Postretirement Benefit Plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Contributions to benefit plans | $ 28,000 | |||
Expected benefit plan contributions to be made during next year | 24,000 | |||
Domestic postretirement benefits plan [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Contributions to benefit plans | 3,554,000 | |||
Expected benefit plan contributions to be made during next year | 5,243,000 | |||
Domestic defined benefit pension plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Contributions to benefit plans | 7,499,000 | |||
Expected benefit plan contributions to be made during next year | 18,459,000 | |||
Foreign Plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Contributions to benefit plans | 687,000 | |||
Expected benefit plan contributions to be made during next year | $ 7,022,000 | |||
United Kingdom [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target interest and inflation rate hedge ratio | 100.00% | |||
Maximum [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Investment Manager's portfolio to be held in equity securities of any one issuer | 10.00% | 10.00% | ||
Equity Securities [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 40.00% | |||
Target allocations of plan assets, maximum | 70.00% | |||
Weighted average expected return on plan asset | 7.91% | |||
Equity Securities [Member] | United Kingdom [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets | 60.00% | |||
Equity Securities [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 40.00% | |||
Target allocations of plan assets, maximum | 75.00% | |||
Target allocations of plan assets | 60.00% | |||
Fixed Income Securities [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 30.00% | |||
Target allocations of plan assets, maximum | 60.00% | |||
Fixed income portfolio, maximum average maturity years | 11 years | |||
Weighted average expected return on plan asset | 4.21% | |||
Fixed Income Securities [Member] | United Kingdom [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets | 40.00% | |||
Fixed Income Securities [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 25.00% | |||
Target allocations of plan assets, maximum | 45.00% | |||
Target allocations of plan assets | 35.00% | |||
US Long/Short Equity Fund [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 0.00% | |||
Target allocations of plan assets, maximum | 15.00% | |||
Cash and Equivalents [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 0.00% | |||
Target allocations of plan assets, maximum | 15.00% | |||
Cash [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Target allocations of plan assets, minimum | 0.00% | |||
Target allocations of plan assets, maximum | 15.00% | |||
Target allocations of plan assets | 5.00% | |||
Emerging Market Commingled Equity Fund [Member] | ||||
Pension and Other Postretirement Benefits Disclosure [Line Items] | ||||
Domestic plan, investment notice period | 10 days |
Employee and Retiree Benefit 83
Employee and Retiree Benefit Plans (Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits [Member] | |||||
Change in benefit obligation | |||||
Obligation at January 1 | $ 815,593 | $ 794,589 | $ 825,552 | $ 815,593 | $ 794,589 |
Service cost | 8,136 | 17,948 | 22,470 | ||
Interest cost | 25,185 | 33,168 | 33,680 | ||
Plan amendments | 8,297 | ||||
Participant contributions | 4 | ||||
Actuarial loss (gain) | 58,236 | (48,019) | |||
Exchange rate changes | (30,447) | (15,337) | |||
Benefits paid | (40,928) | (35,936) | |||
Special termination benefits | 8,606 | ||||
Curtailments | 822 | 306 | |||
Obligation at December 31 | 815,593 | 794,589 | 825,552 | ||
Change in plan assets | |||||
Fair value of plan assets at January 1 | 521,682 | 560,978 | |||
Actual return on plan assets | 61,860 | (18,718) | |||
Employer contributions | 8,186 | 31,442 | |||
Participant contributions | 4 | ||||
Exchange rate changes | (30,609) | (14,104) | |||
Benefits paid | (40,928) | (35,936) | |||
Other | (834) | (1,984) | |||
Fair value of plan assets at December 31 | 519,357 | 521,682 | 560,978 | ||
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 | |||||
Deferred charges and other assets | 7,591 | 7,463 | |||
Other accrued liabilities | (8,184) | (7,487) | |||
Deferred credits and other liabilities | (295,643) | (272,883) | |||
Funded status and net plan liability recognized at December 31 | (296,236) | (272,907) | |||
Other Postretirement Benefits [Member] | |||||
Change in benefit obligation | |||||
Obligation at January 1 | 106,679 | 115,222 | 118,496 | 106,679 | 115,222 |
Service cost | 1,864 | 3,180 | 2,459 | ||
Interest cost | 3,800 | 4,883 | 4,617 | ||
Participant contributions | 1,278 | 1,276 | |||
Actuarial loss (gain) | (10,627) | (7,436) | |||
Medicare Part D subsidy | 510 | 510 | |||
Exchange rate changes | 20 | (112) | |||
Benefits paid | (5,369) | (5,575) | |||
Curtailments | (19) | ||||
Obligation at December 31 | 106,679 | 115,222 | $ 118,496 | ||
Change in plan assets | |||||
Employer contributions | 3,581 | 3,789 | |||
Participant contributions | 1,278 | 1,276 | |||
Medicare Part D subsidy | 510 | 510 | |||
Benefits paid | $ (5,369) | $ (5,575) | |||
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 | |||||
Other accrued liabilities | (5,267) | (5,370) | |||
Deferred credits and other liabilities | (101,412) | (109,852) | |||
Funded status and net plan liability recognized at December 31 | $ (106,679) | $ (115,222) |
Employee and Retiree Benefit 84
Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial loss | $ (247,622) |
Prior service (cost) credit | (6,831) |
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense | (254,453) |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial loss | (2,858) |
Prior service (cost) credit | 112 |
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense | $ (2,746) |
Employee and Retiree Benefit 85
Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial loss | $ (14,257) |
Prior service (cost) credit | (1,019) |
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit cost | (15,276) |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Prior service (cost) credit | 74 |
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit cost | $ 74 |
Employee and Retiree Benefit 86
Employee and Retiree Benefit Plans (Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Funded Defined Benefit Pension Plans [Member] | Qualified Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected Benefit Obligations | $ 643,174 | $ 630,587 |
Accumulated Benefit Obligations | 599,730 | 622,841 |
Fair Value of Plan Assets | 497,894 | 500,695 |
Unfunded Defined Benefit Pension Plans [Member] | Non-Qualified Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected Benefit Obligations | 156,088 | 148,019 |
Accumulated Benefit Obligations | 150,780 | 140,544 |
Unfunded Other Postretirement Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected Benefit Obligations | 106,678 | 115,222 |
Accumulated Benefit Obligations | $ 106,678 | $ 115,222 |
Employee and Retiree Benefit 87
Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 8,136 | $ 17,948 | $ 22,470 |
Interest cost | 25,185 | 33,168 | 33,680 |
Expected return on plan assets | (28,154) | (34,016) | (33,723) |
Amortization of prior service cost (credit) | 1,204 | 1,560 | 899 |
Amortization of transitional (asset) liability | (1) | (480) | |
Recognized actuarial loss | 16,165 | 15,147 | 9,471 |
Gross periodic benefit expense | 22,536 | 33,806 | 32,317 |
Termination benefits expense | 8,606 | ||
Curtailment expense | 822 | 306 | |
Net periodic benefit expense | 23,358 | 42,718 | 32,317 |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 1,864 | 3,180 | 2,459 |
Interest cost | 3,800 | 4,883 | 4,617 |
Amortization of prior service cost (credit) | (75) | (82) | (82) |
Recognized actuarial loss | 5 | 992 | 5 |
Gross periodic benefit expense | 5,594 | 8,973 | 6,999 |
Curtailment expense | (19) | ||
Net periodic benefit expense | $ 5,575 | $ 8,973 | $ 6,999 |
Employee and Retiree Benefit 88
Employee and Retiree Benefit Plans (Amount Related to Foreign Benefit Plans) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Foreign Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Benefit obligation at December 31 | $ 206,502 | $ 197,549 |
Fair value of plan assets at December 31 | 197,575 | 193,933 |
Net plan liabilities recognized | 8,927 | 3,616 |
Net periodic benefit expense (benefit) | (2,244) | 4,703 |
Foreign Other Postretirement Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Benefit obligation at December 31 | 615 | 643 |
Net plan liabilities recognized | 615 | 643 |
Net periodic benefit expense (benefit) | $ 154 | $ 152 |
Employee and Retiree Benefit 89
Employee and Retiree Benefit Plans (Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense) (Details) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Benefit Obligations, Expected return on plan assets | 5.62% | |
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Expected Long Term Return On Assets | 5.62% | |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Benefit Obligations, Discount rate | 3.94% | 4.37% |
Benefit Obligations, Expected return on plan assets | 5.62% | 6.00% |
Benefit Obligation, Rate of compensation increase | 3.52% | 3.74% |
Net Periodic Benefit Expense, Discount rate | 3.84% | 4.04% |
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Expected Long Term Return On Assets | 5.62% | 6.00% |
Net Periodic Benefit Expense, Rate of compensation increase | 3.52% | 3.74% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Benefit Obligations, Discount rate | 4.41% | 4.61% |
Net Periodic Benefit Expense, Discount rate | 4.24% | 4.12% |
Employee and Retiree Benefit 90
Employee and Retiree Benefit Plans (Benefit Payments, Reflected Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,017 | $ 38,532 |
2,018 | 38,896 |
2,019 | 39,833 |
2,020 | 40,848 |
2,021 | 41,653 |
2022-2026 | 221,350 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,017 | 6,161 |
2,018 | 6,319 |
2,019 | 6,435 |
2,020 | 6,621 |
2,021 | 6,824 |
2022-2026 | $ 36,326 |
Employee and Retiree Benefit 91
Employee and Retiree Benefit Plans (One Percent Change in Assumed Health Care Cost Trend Rates) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Employee and Retiree Benefit Plans [Abstract] | |
1% Increase, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2016 | $ 1,076 |
1% Increase, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2016 | 15,246 |
1% Decrease, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2016 | (818) |
1% Decrease, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2016 | $ (12,251) |
Employee and Retiree Benefit 92
Employee and Retiree Benefit Plans (Weighted Average Asset Allocation for Company's Funded Pension Benefit Plans) (Details) | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | ||
Weighted average asset allocation | 100.00% | 100.00% |
Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Weighted average asset allocation | 58.40% | 64.40% |
Fixed Income Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Weighted average asset allocation | 39.00% | 34.00% |
Cash Equivalents [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Weighted average asset allocation | 2.60% | 1.60% |
Employee and Retiree Benefit 93
Employee and Retiree Benefit Plans (Fair Value Measurements of Retirement Plan Assets within Fair Value of Hierarchy) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 321,782 | $ 327,749 | |
Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 197,575 | 193,933 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 519,357 | 521,682 | $ 560,978 |
Level 1 [Member] | Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 92,478 | 85,341 | |
Level 1 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 734 | ||
Level 1 [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 92,478 | 86,075 | |
Level 2 [Member] | Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 195,190 | 208,479 | |
Level 2 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 197,575 | 193,199 | |
Level 2 [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 392,765 | 401,678 | |
Level 3 [Member] | Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 34,114 | 33,929 | |
Level 3 [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 34,114 | 33,929 | |
Equity Securities [Member] | Domestic Plans [Member] | US Core Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 61,554 | 51,878 | |
Equity Securities [Member] | Domestic Plans [Member] | U.S. Small/Midcap [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 23,103 | 26,964 | |
Equity Securities [Member] | Domestic Plans [Member] | Hedged Funds and Other Alternative Strategies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 48,113 | 50,878 | |
Equity Securities [Member] | Domestic Plans [Member] | International Commingled Trust Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 67,451 | 72,205 | |
Equity Securities [Member] | Domestic Plans [Member] | Emerging Market Commingled Equity Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 16,006 | 16,873 | |
Equity Securities [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 74,108 | 104,718 | |
Equity Securities [Member] | Level 1 [Member] | Domestic Plans [Member] | US Core Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 61,554 | 51,878 | |
Equity Securities [Member] | Level 1 [Member] | Domestic Plans [Member] | U.S. Small/Midcap [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 23,103 | 26,964 | |
Equity Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | Hedged Funds and Other Alternative Strategies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 13,999 | 16,949 | |
Equity Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | International Commingled Trust Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 67,451 | 72,205 | |
Equity Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | Emerging Market Commingled Equity Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 16,006 | 16,873 | |
Equity Securities [Member] | Level 2 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 74,108 | 104,718 | |
Equity Securities [Member] | Level 3 [Member] | Domestic Plans [Member] | Hedged Funds and Other Alternative Strategies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 34,114 | 33,929 | |
Fixed Income Securities [Member] | Domestic Plans [Member] | International Commingled Trust Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 13,486 | 15,332 | |
Fixed Income Securities [Member] | Domestic Plans [Member] | U.S. Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 78,473 | 80,681 | |
Fixed Income Securities [Member] | Domestic Plans [Member] | Emerging Market Mutual Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 5,775 | 6,439 | |
Fixed Income Securities [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 97,075 | 67,494 | |
Fixed Income Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | International Commingled Trust Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 13,486 | 15,332 | |
Fixed Income Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | U.S. Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 78,473 | 80,681 | |
Fixed Income Securities [Member] | Level 2 [Member] | Domestic Plans [Member] | Emerging Market Mutual Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 5,775 | 6,439 | |
Fixed Income Securities [Member] | Level 2 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 97,075 | 67,494 | |
Diversified Pooled Fund [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 21,463 | 20,987 | |
Diversified Pooled Fund [Member] | Level 2 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 21,463 | 20,987 | |
Cash and Equivalents [Member] | Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 7,821 | 6,499 | |
Cash and Equivalents [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 4,929 | 734 | |
Cash and Equivalents [Member] | Level 1 [Member] | Domestic Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 7,821 | 6,499 | |
Cash and Equivalents [Member] | Level 1 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 734 | ||
Cash and Equivalents [Member] | Level 2 [Member] | Foreign Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 4,929 |
Employee and Retiree Benefit 94
Employee and Retiree Benefit Plans (Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Insurance [Abstract] | ||
Beginning Balance | $ 33,929 | $ 33,952 |
Relating to assets held at the reporting date | 185 | (23) |
Relating to assets sold during the period | ||
Purchases, sales and settlements | ||
Ending Balance | $ 34,114 | $ 33,929 |
Financial Instruments and Ris95
Financial Instruments and Risk Management (Narrative) (Details) | 12 Months Ended | ||||
Dec. 31, 2017bbl / d | Dec. 31, 2016USD ($)bbl / d | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | May 31, 2012USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Amount of loss reclassified to interest expense | $ 2,963,000 | $ 2,963,000 | $ 2,963,000 | ||
Amount of loss expected to be reclassified to interest expense in the next 12 months | 2,963,000 | ||||
Loss deferred for fair value of interest rate derivative contracts, net of tax | 15,926,000 | ||||
Income tax on deferred loss on fair value of interest rate derivative contracts | $ 5,574,000 | ||||
Commodity Derivative Contracts [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Daily production commitment (barrels per day) | bbl / d | 20,000 | ||||
Fair value of derivative contract liability | $ 48,900,000 | ||||
Fair value of derivative contract asset | 89,400,000 | ||||
Increase (decrease) of income before taxes due to the impact of marking to market of derivative contracts | (47,703,000) | 77,300,000 | |||
Commodity Derivative Contracts [Member] | Scenario, Forecast [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Daily production commitment (barrels per day) | bbl / d | 22,000 | ||||
Interest Rate Swap [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Face amount of notes | $ 350,000,000 | ||||
Foreign Exchange Derivative Contracts [Member] | Currency, U.S. Dollar [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Short-term derivative instruments | 14,200,000 | 4,800,000 | |||
Accounts Payable [Member] | Foreign Exchange Derivative Contracts [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Fair value of foreign derivative contracts | 73,000 | 29,000 | |||
Accounts Payable [Member] | Nondesignated [Member] | Commodity Derivative Contracts [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Fair value of foreign derivative contracts | 48,864,000 | ||||
Accounts Payable [Member] | Nondesignated [Member] | Foreign Exchange Derivative Contracts [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Fair value of foreign derivative contracts | $ 73,000 | 29,000 | |||
Accounts Receivable [Member] | Nondesignated [Member] | Commodity Derivative Contracts [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Fair value of derivative contract asset | $ 89,358,000 |
Financial Instruments and Ris96
Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Commodity Derivative Contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | $ 89,400,000 | |
Foreign Exchange Derivative Contracts [Member] | Accounts Payable [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | $ 73,000 | 29,000 |
Nondesignated [Member] | Commodity Derivative Contracts [Member] | Accounts Receivable [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 89,358,000 | |
Nondesignated [Member] | Commodity Derivative Contracts [Member] | Accounts Payable [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 48,864,000 | |
Nondesignated [Member] | Foreign Exchange Derivative Contracts [Member] | Accounts Payable [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | $ 73,000 | $ 29,000 |
Financial Instruments and Ris97
Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) | $ (36,698) | $ 129,060 |
Commodity Derivative Contracts [Member] | Sales And Other Operating Revenues [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) | (63,412) | 129,064 |
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income (Loss) [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) | $ 26,714 | $ (4) |
Stockholders' Equity (Summary O
Stockholders' Equity (Summary Of Shares Repurchased) (Details) | 12 Months Ended | ||
Dec. 31, 2016itemshares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | |
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | |||
Purchase of Treasury Stock | $ | $ 250,000,000 | $ 375,000,000 | |
Shares repurchased | shares | 0 | 5,967,313 | 6,373,718 |
Number of open share buyback programs | item | 0 |
Earnings per Share (Weighted-Av
Earnings per Share (Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share) (Details) - shares | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Earnings per Share [Abstract] | ||||
Basic method | 172,173,012 | 174,351,227 | 178,852,942 | |
Dilutive stock options and restricted stock units | 0 | 0 | 1,218,042 | [1] |
Diluted method | 172,173,012 | 174,351,227 | 180,070,984 | |
[1] | Due to a net loss recognized by the Company for the year ended December 31, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive. |
Earnings per Share (Anti Diluti
Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings per Share [Abstract] | |||
Antidilutive stock options excluded from diluted shares (in shares) | 5,757,435 | 5,443,288 | 1,893,364 |
Weighted average price of these options (per share) | $ 48.46 | $ 52.93 | $ 55.21 |
Other Financial Information (Na
Other Financial Information (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($) | |
Other Financial Information [Line Items] | |||
Deepwater rig contract exit costs | $ (4,344,000) | $ 282,001,000 | |
Payment of contract exit costs | 266,700,000 | ||
Write down of accrued contract exit costs | 4,330,000 | ||
Net gains (losses) from foreign currency transactions | $ 59,731,000 | $ 87,961,000 | $ 40,596,000 |
Gulf Of Mexico [Member] | |||
Other Financial Information [Line Items] | |||
Number of deepwater drilling rigs | item | 2 |
Other Financial Information (No
Other Financial Information (Noncash Opearting Working Capital) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Financial Information [Abstract] | |||
Accounts receivable | $ 119,671 | $ 297,625 | $ 175,820 |
Inventories | (5,171) | (15,340) | 25,697 |
Prepaid expenses | 149,946 | (144,845) | 6,575 |
Deferred income tax assets | 3,924 | 6,884 | |
Accounts payable and accrued liabilities | (328,078) | (36,887) | (54,785) |
Current income tax liabilities | 24,943 | (69,413) | (163,920) |
Net (increase) decrease in noncash operating working capital | (38,689) | 35,064 | (3,729) |
Cash income taxes paid, net of refunds | 6,707 | 118,667 | 573,799 |
Interest paid, net of amounts capitalized | 127,798 | 110,386 | 114,232 |
Asset retirement costs capitalized | 13,690 | 76,775 | 70,568 |
Decrease in capital expenditure accrual | $ 158,885 | $ 462,474 | $ 93,080 |
Accumulated Other Comprehens103
Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||||
Beginning Balance | [1] | $ (704,542,000) | [2] | $ (170,255,000) | ||
Before reclassifications to income | [1] | 62,686,000 | (593,918,000) | |||
Reclassifications to income | [1] | 13,644,000 | 59,631,000 | |||
Net other comprehensive income (loss) | 76,330,000 | [1] | (534,287,000) | [1] | $ (342,374,000) | |
Ending Balance | [1] | (628,212,000) | (704,542,000) | [2] | (170,255,000) | |
Reclassifications before taxes, included in net periodic benefit expense | 18,036,000 | 21,721,000 | ||||
Reclassifications income tax, included in net periodic benefit expense | 6,318,000 | 5,761,000 | ||||
Amount of loss reclassified to interest expense | 2,963,000 | 2,963,000 | 2,963,000 | |||
Reclassifications income tax, included in interest expense | 1,037,000 | 1,037,000 | ||||
Foreign Currency Translation Gains (Losses) [Member] | ||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||||
Beginning Balance | [1] | (513,004,000) | 33,701,000 | |||
Before reclassifications to income | [1] | 66,449,000 | (588,450,000) | |||
Reclassifications to income | [1],[3] | 41,745,000 | ||||
Net other comprehensive income (loss) | [1] | 66,449,000 | (546,705,000) | |||
Ending Balance | [1] | (446,555,000) | (513,004,000) | 33,701,000 | ||
Retirement and Postretirement Benefit Plan Adjustments [Member] | ||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||||
Beginning Balance | [1] | (179,260,000) | (189,752,000) | |||
Before reclassifications to income | [1] | (3,763,000) | (5,468,000) | |||
Reclassifications to income | [1],[4] | 11,718,000 | 15,960,000 | |||
Net other comprehensive income (loss) | [1] | 7,955,000 | 10,492,000 | |||
Ending Balance | [1] | (171,305,000) | (179,260,000) | (189,752,000) | ||
Deferred Loss On Interest Rate Derivative Hedges [Member] | ||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||||
Beginning Balance | [1] | (12,278,000) | (14,204,000) | |||
Reclassifications to income | [1],[5] | 1,926,000 | 1,926,000 | |||
Net other comprehensive income (loss) | [1] | 1,926,000 | 1,926,000 | |||
Ending Balance | [1] | $ (10,352,000) | $ (12,278,000) | $ (14,204,000) | ||
[1] | All amounts are presented net of income taxes. | |||||
[2] | Reclassified to conform to current presentation. See Note B for additional information. | |||||
[3] | Reclassification for the year ended December 31, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K. | |||||
[4] | Reclassifications before taxes of $21,721 and $18,036 are included in the computation of net periodic benefit expense in 2015 and 2016, respectively. See Note K for additional information. Related income taxes of $5,761 and $6,318 are included in income tax expense in 2015 and 2016, respectively. | |||||
[5] | Reclassifications before taxes of $2,963 are included in Interest expense in both 2015 and 2016. Related income taxes of $1,037 are included in income tax expense in 2015 and 2016. See Note L for additional information. |
Assets and Liabilities Measu104
Assets and Liabilities Measured at Fair Value (Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Commodity derivative contracts | $ 89,358 | |
Assets, Total | 89,358 | |
Liabilities, Nonqualified employee savings plan | $ 13,904 | 12,971 |
Liabilities, Commodity derivative contracts | 48,864 | |
Liabilities, Foreign currency exchange derivative contracts | 73 | 29 |
Liabilities, Total | 62,841 | 13,000 |
Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Liabilities, Nonqualified employee savings plan | 13,904 | 12,971 |
Liabilities, Total | 13,904 | 12,971 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Commodity derivative contracts | 89,358 | |
Assets, Total | 89,358 | |
Liabilities, Commodity derivative contracts | 48,864 | |
Liabilities, Foreign currency exchange derivative contracts | 73 | 29 |
Liabilities, Total | $ 48,937 | $ 29 |
Assets and Liabilities Measu105
Assets and Liabilities Measured at Fair Value (Carrying Amounts and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Financial assets (liabilities), Carrying value | |||
Canadian government securities with maturities greater than 90 days at the date of acquisition | $ 111,542 | $ 173,288 | [1] |
Current and long-term debt | (2,992,567) | (3,059,475) | |
Financial assets (liabilities): | |||
Canadian government securities with maturities greater than 90 days at the date of acquisition | 111,331 | 173,234 | |
Current and long-term debt | $ (2,951,992) | $ (2,189,858) | |
[1] | Reclassified to conform to current presentation. See Note B for additional information. |
Assets and Liabilities Measu106
Assets and Liabilities Measured at Fair Value (Nonrecurring Fair Value Measurements) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Net Book Value Prior to Impairment | $ 167,055,000 | $ 4,033,688,000 | ||||
Total Pretax (Noncash) Impairment Expense | 95,088,000 | 2,493,156,000 | $ 51,314,000 | |||
Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Assets: Impaired proved properties | 71,967,000 | 1,540,532,000 | ||||
Canada [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Net Book Value Prior to Impairment | 167,055,000 | |||||
Total Pretax (Noncash) Impairment Expense | $ 37,047,000 | 95,088,000 | 683,574,000 | 37,047,000 | [1] | |
Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Assets: Impaired proved properties | 71,967,000 | |||||
Gulf Of Mexico [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Net Book Value Prior to Impairment | 645,088,000 | |||||
Total Pretax (Noncash) Impairment Expense | 328,982,000 | 14,267,000 | ||||
Gulf Of Mexico [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Assets: Impaired proved properties | 316,106,000 | |||||
Malaysia [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Net Book Value Prior to Impairment | 2,681,500,000 | |||||
Total Pretax (Noncash) Impairment Expense | [2] | 1,480,600,000 | ||||
Malaysia [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Assets: Impaired proved properties | 1,200,900,000 | |||||
Conventional [Member] | Canada [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Total Pretax (Noncash) Impairment Expense | [2] | $ 95,100,000 | 683,600,000 | $ 37,000,000 | ||
Conventional [Member] | Western Canada [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Net Book Value Prior to Impairment | 707,100,000 | |||||
Total Pretax (Noncash) Impairment Expense | 683,574,000 | |||||
Conventional [Member] | Western Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Assets: Impaired proved properties | $ 23,526,000 | |||||
[1] | This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. | |||||
[2] | Results exclude corporate overhead, interest and discontinued operations. |
Commitments (Narrative) (Detail
Commitments (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Line Items] | |||
Operating lease rental payments due in 2017 | $ 71,335,000 | ||
Operating lease rental payments due in 2018 | 67,586,000 | ||
Operating lease rental payments due in 2019 | 54,672,000 | ||
Operating lease rental payments due in 2020 | 54,423,000 | ||
Operating lease rental payments due in 2021 | 54,622,000 | ||
Rental expenses for non-cancellable lease, including contingent payments | 77,520,000 | $ 111,425,000 | $ 144,981,000 |
Commitments for capital expenditures | 585,651,000 | ||
Malaysia [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 224,485,000 | ||
Kaybob Duvernay Lands, Alberta [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 156,984,000 | ||
Gulf Of Mexico [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 25,202,000 | ||
Eagle Ford Shale [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 107,002,000 | ||
Vietnam [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 27,178,000 | ||
Brunei [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 12,828,000 | ||
Drilling Rigs And Associated Equipment [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitments for capital expenditures | 45,042,000 | ||
Processing Production Handling and Transportation Services [Member] | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Operating lease rental payments due in 2017 | 53,893,000 | ||
Operating lease rental payments due in 2018 | 48,962,000 | ||
Operating lease rental payments due in 2019 | 42,616,000 | ||
Operating lease rental payments due in 2020 | 46,597,000 | ||
Operating lease rental payments due in 2021 | 47,793,000 | ||
Processing and transportation charges | $ 50,300,000 | $ 32,473,000 | $ 34,597,000 |
Contingencies (Narrative) (Deta
Contingencies (Narrative) (Details) - Canada [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Contingencies Disclosure [Line Items] | |
Remediation costs | $ 43.9 |
Payments for environmental liabilities | $ 35.3 |
Common Stock Issued and Outs109
Common Stock Issued and Outstanding (Activity in the Number of Common Stock Shares Issued and Outstanding) (Details) - shares | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Stockholders; Equity, Common Stock Issued and Outstanding [Abstract] | ||||
At beginning of year | 172,034,711 | 177,499,513 | 183,406,513 | |
Stock options exercised | [1] | 15,575 | 119,994 | |
Restricted stock awards | [1] | 158,504 | 478,549 | 339,985 |
Employee stock purchase and thrift plans | 8,962 | 8,387 | 6,739 | |
Treasury shares purchased | (5,967,313) | (6,373,718) | ||
At end of year | 172,202,177 | 172,034,711 | 177,499,513 | |
[1] | Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares. |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jan. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Subsequent Event [Line Items] | |||||
Proceeds from sales of property, plant and equipment | $ 1,155,144 | $ 423,911 | $ 1,467,046 | ||
Gain on sale of assets | $ 1,663 | $ 154,155 | $ 138,903 | ||
Western Canada [Member] | Scenario, Forecast [Member] | |||||
Subsequent Event [Line Items] | |||||
Gain on sale of assets | $ 132,400 | ||||
Subsequent Event [Member] | Western Canada [Member] | |||||
Subsequent Event [Line Items] | |||||
Proceeds from sales of property, plant and equipment | $ 49,000 |
Business Segments (Narrative) (
Business Segments (Narrative) (Details) - Sales Revenue [Member] | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Phillips 66 and Affiliated Companies [Member] | |||
Segment Reporting Information [Line Items] | |||
Concentration risk | 17.00% | 17.00% | 14.00% |
Shell Oil and Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Concentration risk | 20.00% |
Business Segments (Segment Info
Business Segments (Segment Information) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | $ (63,900,000) | $ (16,200,000) | $ 2,900,000 | $ (198,800,000) | $ (587,100,000) | $ (1,595,400,000) | $ (73,800,000) | $ (14,500,000) | $ (275,970,000) | $ (2,270,833,000) | $ 905,611,000 | |||||
Revenues from external customers | 1,874,129,000 | 3,033,080,000 | 5,476,084,000 | |||||||||||||
Income tax expense (benefit) | (219,172,000) | (1,026,490,000) | 227,297,000 | |||||||||||||
Depreciation, depletion and amortization | 1,054,081,000 | 1,619,824,000 | 1,906,247,000 | |||||||||||||
Accretion of asset retirement obligations | 46,742,000 | 48,665,000 | 50,778,000 | |||||||||||||
Amortization of undeveloped leases | 43,417,000 | 75,312,000 | 74,438,000 | |||||||||||||
Impairment of assets | 95,088,000 | 2,493,156,000 | 51,314,000 | |||||||||||||
Total assets at year end | 10,295,860,000 | 11,493,812,000 | [1] | 10,295,860,000 | 11,493,812,000 | [1] | ||||||||||
Discontinued Operations [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (2,000,000) | (15,000,000) | (119,400,000) | |||||||||||||
Total assets at year end | 27,100,000 | 38,300,000 | $ 427,100,000 | 27,100,000 | 38,300,000 | 427,100,000 | ||||||||||
United States [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Revenues from external customers | 693,200,000 | 1,260,000,000 | 2,201,500,000 | |||||||||||||
Impairment of assets | [2] | 329,000,000 | 14,300,000 | |||||||||||||
Canada [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Revenues from external customers | 421,100,000 | 557,300,000 | 1,052,400,000 | |||||||||||||
Impairment of assets | 37,047,000 | 95,088,000 | 683,574,000 | 37,047,000 | [3] | |||||||||||
Malaysia [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Revenues from external customers | 759,300,000 | 1,210,900,000 | 2,233,000,000 | |||||||||||||
Impairment of assets | [2] | 1,480,600,000 | ||||||||||||||
Other [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Revenues from external customers | 500,000 | 4,900,000 | (10,800,000) | |||||||||||||
Operating Segments [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (276,000,000) | (2,270,800,000) | 905,600,000 | |||||||||||||
Revenues from external customers | 1,874,100,000 | 3,033,100,000 | ||||||||||||||
Interest income | 2,900,000 | 4,000,000 | 7,700,000 | |||||||||||||
Interest expense, net of capitalization | 148,200,000 | 117,400,000 | 115,800,000 | |||||||||||||
Income tax expense (benefit) | (219,200,000) | (1,026,500,000) | 227,300,000 | |||||||||||||
Depreciation, depletion and amortization | 1,054,100,000 | 1,619,800,000 | 1,906,200,000 | |||||||||||||
Accretion of asset retirement obligations | 46,700,000 | 48,700,000 | 50,800,000 | |||||||||||||
Amortization of undeveloped leases | 43,400,000 | 75,400,000 | 74,400,000 | |||||||||||||
Impairment of assets | 95,100,000 | 2,493,200,000 | 51,300,000 | |||||||||||||
Deferred and noncurrent income taxes | (387,800,000) | (978,000,000) | (170,900,000) | |||||||||||||
Additions to property, plant, equipment | 753,100,000 | 1,791,500,000 | 3,317,800,000 | |||||||||||||
Total assets at year end | 10,295,900,000 | 11,493,800,000 | 16,742,300,000 | 10,295,900,000 | 11,493,800,000 | 16,742,300,000 | ||||||||||
Exploration and production [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (124,900,000) | (2,010,900,000) | 1,189,800,000 | |||||||||||||
Revenues from external customers | 1,804,600,000 | 2,934,700,000 | 5,422,700,000 | |||||||||||||
Interest income | 0 | 0 | 0 | |||||||||||||
Interest expense, net of capitalization | 0 | 0 | 0 | |||||||||||||
Income tax expense (benefit) | (155,100,000) | (1,111,000,000) | 285,700,000 | |||||||||||||
Depreciation, depletion and amortization | 1,037,300,000 | 1,607,900,000 | 1,897,500,000 | |||||||||||||
Accretion of asset retirement obligations | 46,700,000 | 48,700,000 | 50,800,000 | |||||||||||||
Amortization of undeveloped leases | 43,400,000 | 75,400,000 | 74,400,000 | |||||||||||||
Impairment of assets | 95,100,000 | 2,493,200,000 | 51,300,000 | |||||||||||||
Deferred and noncurrent income taxes | (311,000,000) | (917,500,000) | (152,100,000) | |||||||||||||
Additions to property, plant, equipment | 731,200,000 | 1,731,600,000 | 3,303,300,000 | |||||||||||||
Total assets at year end | 9,118,900,000 | 10,863,300,000 | 14,541,300,000 | 9,118,900,000 | 10,863,300,000 | 14,541,300,000 | ||||||||||
Exploration and production [Member] | United States [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (205,400,000) | (615,700,000) | 387,100,000 | |||||||||||||
Revenues from external customers | 685,700,000 | 1,253,600,000 | 2,196,400,000 | |||||||||||||
Interest income | 0 | 0 | 0 | |||||||||||||
Interest expense, net of capitalization | 0 | 0 | 0 | |||||||||||||
Income tax expense (benefit) | (87,900,000) | (337,000,000) | 214,800,000 | |||||||||||||
Depreciation, depletion and amortization | 600,500,000 | 794,900,000 | 840,700,000 | |||||||||||||
Accretion of asset retirement obligations | 17,100,000 | 20,200,000 | 17,500,000 | |||||||||||||
Amortization of undeveloped leases | 38,400,000 | 59,200,000 | 50,100,000 | |||||||||||||
Impairment of assets | 0 | 329,000,000 | 14,300,000 | |||||||||||||
Deferred and noncurrent income taxes | (108,400,000) | (187,700,000) | 39,700,000 | |||||||||||||
Additions to property, plant, equipment | 269,800,000 | 1,263,100,000 | 2,028,700,000 | |||||||||||||
Total assets at year end | 5,419,000,000 | 5,717,800,000 | 5,745,700,000 | 5,419,000,000 | 5,717,800,000 | 5,745,700,000 | ||||||||||
Exploration and production [Member] | Canada [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (35,900,000) | (583,400,000) | 156,500,000 | |||||||||||||
Revenues from external customers | 365,300,000 | 549,700,000 | 1,044,100,000 | |||||||||||||
Interest income | 0 | 0 | 0 | |||||||||||||
Interest expense, net of capitalization | 0 | 0 | 0 | |||||||||||||
Income tax expense (benefit) | (134,300,000) | (188,800,000) | 64,200,000 | |||||||||||||
Depreciation, depletion and amortization | 203,200,000 | 261,900,000 | 316,700,000 | |||||||||||||
Accretion of asset retirement obligations | 13,300,000 | 12,600,000 | 15,200,000 | |||||||||||||
Amortization of undeveloped leases | 4,500,000 | 14,400,000 | 19,400,000 | |||||||||||||
Impairment of assets | 95,100,000 | 683,600,000 | 37,000,000 | |||||||||||||
Deferred and noncurrent income taxes | (175,800,000) | (146,000,000) | 43,300,000 | |||||||||||||
Additions to property, plant, equipment | 361,300,000 | 184,900,000 | 445,900,000 | |||||||||||||
Total assets at year end | 1,559,500,000 | 2,460,600,000 | 3,769,800,000 | 1,559,500,000 | 2,460,600,000 | 3,769,800,000 | ||||||||||
Exploration and production [Member] | Malaysia [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | 171,100,000 | (653,200,000) | 896,200,000 | |||||||||||||
Revenues from external customers | 753,400,000 | 1,131,400,000 | 2,183,500,000 | |||||||||||||
Interest income | 0 | 0 | 0 | |||||||||||||
Interest expense, net of capitalization | 0 | 0 | 0 | |||||||||||||
Income tax expense (benefit) | 85,900,000 | (567,900,000) | 102,600,000 | |||||||||||||
Depreciation, depletion and amortization | 227,700,000 | 544,900,000 | 735,000,000 | |||||||||||||
Accretion of asset retirement obligations | 16,300,000 | 15,900,000 | 18,100,000 | |||||||||||||
Amortization of undeveloped leases | 0 | 0 | 0 | |||||||||||||
Impairment of assets | 0 | 1,480,600,000 | 0 | |||||||||||||
Deferred and noncurrent income taxes | (8,500,000) | (579,200,000) | (235,100,000) | |||||||||||||
Additions to property, plant, equipment | 101,400,000 | 244,400,000 | 818,000,000 | |||||||||||||
Total assets at year end | 2,024,700,000 | 2,537,200,000 | 4,887,100,000 | 2,024,700,000 | 2,537,200,000 | 4,887,100,000 | ||||||||||
Exploration and production [Member] | Other [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (54,700,000) | (158,600,000) | (250,000,000) | |||||||||||||
Revenues from external customers | 200,000 | 0 | (1,300,000) | |||||||||||||
Interest income | 0 | 0 | 0 | |||||||||||||
Interest expense, net of capitalization | 0 | 0 | 0 | |||||||||||||
Income tax expense (benefit) | (18,800,000) | (17,300,000) | (95,900,000) | |||||||||||||
Depreciation, depletion and amortization | 5,900,000 | 6,200,000 | 5,100,000 | |||||||||||||
Accretion of asset retirement obligations | 0 | 0 | 0 | |||||||||||||
Amortization of undeveloped leases | 500,000 | 1,800,000 | 4,900,000 | |||||||||||||
Impairment of assets | 0 | 0 | 0 | |||||||||||||
Deferred and noncurrent income taxes | (18,300,000) | (4,600,000) | 0 | |||||||||||||
Additions to property, plant, equipment | (1,300,000) | 39,200,000 | 10,700,000 | |||||||||||||
Total assets at year end | 115,700,000 | 147,700,000 | 138,700,000 | 115,700,000 | 147,700,000 | 138,700,000 | ||||||||||
Corporate and Other [Member] | ||||||||||||||||
Revenues From External Customers And Long Lived Assets [Line Items] | ||||||||||||||||
Net income (loss) | (149,100,000) | (244,900,000) | (164,800,000) | |||||||||||||
Revenues from external customers | 69,500,000 | 98,400,000 | ||||||||||||||
Interest income | 2,900,000 | 4,000,000 | 7,700,000 | |||||||||||||
Interest expense, net of capitalization | 148,200,000 | 117,400,000 | 115,800,000 | |||||||||||||
Income tax expense (benefit) | (64,100,000) | 84,500,000 | (58,400,000) | |||||||||||||
Depreciation, depletion and amortization | 16,800,000 | 11,900,000 | 8,700,000 | |||||||||||||
Accretion of asset retirement obligations | 0 | 0 | 0 | |||||||||||||
Amortization of undeveloped leases | 0 | 0 | 0 | |||||||||||||
Impairment of assets | 0 | 0 | 0 | |||||||||||||
Deferred and noncurrent income taxes | (76,800,000) | (60,500,000) | (18,800,000) | |||||||||||||
Additions to property, plant, equipment | 21,900,000 | 59,900,000 | 14,500,000 | |||||||||||||
Total assets at year end | $ 1,149,900,000 | $ 592,200,000 | $ 1,773,900,000 | $ 1,149,900,000 | $ 592,200,000 | $ 1,773,900,000 | ||||||||||
[1] | Reclassified to conform to current presentation. See Note B for additional information. | |||||||||||||||
[2] | Results exclude corporate overhead, interest and discontinued operations. | |||||||||||||||
[3] | This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. |
Business Segments (Geographic I
Business Segments (Geographic Information on Certain Long-Lived Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | $ 8,316.2 | $ 9,818.4 | $ 13,331.4 |
United States [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | 5,121.6 | 5,484.7 | 5,419.5 |
Canada [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | 1,451.4 | 2,310.6 | 3,574.6 |
Malaysia [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | 1,637 | 1,912 | 4,258.8 |
United Kingdom [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | 0.4 | ||
Other [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Certain Long-Lived Assets | $ 106.2 | $ 111.1 | $ 78.1 |
Business Segments (Geographi114
Business Segments (Geographic Information on Revenues from External Customers) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
External Revenues | $ 1,874,129 | $ 3,033,080 | $ 5,476,084 |
United States [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
External Revenues | 693,200 | 1,260,000 | 2,201,500 |
Canada [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
External Revenues | 421,100 | 557,300 | 1,052,400 |
Malaysia [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
External Revenues | 759,300 | 1,210,900 | 2,233,000 |
Other [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
External Revenues | $ 500 | $ 4,900 | $ (10,800) |
Supplemental Oil and Gas Inf115
Supplemental Oil and Gas Information (Narrative) (Details) Mcfe in Millions, ft³ in Billions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2015 | Dec. 31, 2016T / bblMcfe$ / bblft³ | Dec. 31, 2014 | |
Reserve Quantities [Line Items] | |||
Percentage of bitumen from total bulk tar sand mined | 10.00% | ||
Percentage of bitumen removed by extraction process that is contained within the tar sand | 90.00% | ||
Metric tons of oil sand used to produce one barrel of synthetic crude oil | T / bbl | 2 | ||
Natural gas proved reserves expected to receive sale proceeds, per thousand cubic foot | $ / bbl | 0.24 | ||
Future net cash flows annual discount factor, percentage | 10.00% | ||
Oil Reserves [Member] | |||
Reserve Quantities [Line Items] | |||
Oil and natural gas reserves associated with the production sharing contracts | Mcfe | 66.2 | ||
Minimum [Member] | |||
Reserve Quantities [Line Items] | |||
Catalytic cracking process efficiency level | 85.00% | ||
Maximum [Member] | |||
Reserve Quantities [Line Items] | |||
Catalytic cracking process efficiency level | 90.00% | ||
Canada [Member] | Synthetic Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Interest in synthetic oil operations at Syncrude in Western Canada, percentage | 5.00% | ||
Process of mining tar sands and converting the raw bitumen into a pipeline-quality crude | The high-density core-hole drilling, at a spacing of less than 500 meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content. | ||
Malaysia [Member] | |||
Reserve Quantities [Line Items] | |||
Percentage of interest in oil and gas property sold during period | 10.00% | 20.00% | |
Malaysia [Member] | Natural Gas Reserves [Member] | Kikeh Field [Member] | |||
Reserve Quantities [Line Items] | |||
Oil and natural gas reserves associated with the production sharing contracts | ft³ | 26.5 |
Supplemental Oil and Gas Inf116
Supplemental Oil and Gas Information (Summary of Proved Reserves Based on Average Prices) (Details) MMBbls in Millions, ft³ in Billions | 12 Months Ended | |||
Dec. 31, 2016MMBblsft³ | Dec. 31, 2015MMBblsft³ | Dec. 31, 2014MMBblsft³ | Dec. 31, 2013MMBblsft³ | |
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 456.2 | 441.8 | 471.2 | |
Revisions of previous estimates | (5.8) | 5.3 | (9.3) | |
Improved recovery | 2.4 | 7.5 | ||
Extensions and discoveries | 11 | 63.8 | 42.6 | |
Purchases of properties | 26.3 | 6.1 | ||
Sales of properties | (121) | (11) | (24.3) | |
Production | (37.7) | (46.1) | (52) | |
Proved developed and undeveloped reserves, Ending Balance | 329 | 456.2 | 441.8 | |
Proved developed reserves | 184.9 | 326.6 | 324.1 | 289.9 |
Proved undeveloped reserves | 144.1 | 129.6 | 117.7 | 181.3 |
Crude Oil [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 341.4 | 336.2 | 354.2 | |
Revisions of previous estimates | (5.8) | (8.2) | (2.3) | |
Improved recovery | 2.4 | 7.5 | ||
Extensions and discoveries | 11 | 63.8 | 42.6 | |
Purchases of properties | 26.3 | 6.1 | ||
Sales of properties | (7.8) | (11) | (24.3) | |
Production | (36.1) | (41.8) | (47.6) | |
Proved developed and undeveloped reserves, Ending Balance | 329 | 341.4 | 336.2 | |
Proved developed reserves | 184.9 | 211.8 | 218.5 | 172.9 |
Proved undeveloped reserves | 144.1 | 129.6 | 117.7 | 181.3 |
Natural Gas Liquids Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 36.4 | 30.6 | 24.4 | |
Revisions of previous estimates | 1.6 | 2 | 5.1 | |
Extensions and discoveries | 2.9 | 7.6 | 4.7 | |
Purchases of properties | 5.1 | |||
Sales of properties | (0.1) | (0.2) | ||
Production | (3.5) | (3.7) | (3.4) | |
Proved developed and undeveloped reserves, Ending Balance | 42.5 | 36.4 | 30.6 | |
Proved developed reserves | 22.2 | 21.6 | 17.5 | 14.2 |
Proved undeveloped reserves | 20.3 | 14.8 | 13.1 | 10.2 |
Natural Gas Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | ft³ | 1,688.8 | 1,704.7 | 1,153.6 | |
Revisions of previous estimates | ft³ | 43.3 | 53.5 | 167.2 | |
Improved recovery | ft³ | 1.8 | 7 | ||
Extensions and discoveries | ft³ | 164.2 | 162.9 | 696.8 | |
Purchases of properties | ft³ | 122.3 | 5.5 | ||
Sales of properties | ft³ | (2.2) | (78) | (162.6) | |
Production | ft³ | (138.4) | (156.1) | (162.8) | |
Proved developed and undeveloped reserves, Ending Balance | ft³ | 1,878 | 1,688.8 | 1,704.7 | |
Proved developed reserves | ft³ | 818.1 | 783.5 | 812.1 | 786.2 |
Proved undeveloped reserves | ft³ | 1,059.9 | 905.3 | 892.6 | 367.4 |
United States [Member] | Crude Oil [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 238.9 | 204.9 | 191.5 | |
Revisions of previous estimates | (10.9) | (7.6) | (3.2) | |
Extensions and discoveries | 8.6 | 63.8 | 32.7 | |
Purchases of properties | 6.1 | |||
Sales of properties | (4.5) | (0.3) | ||
Production | (17.7) | (22.2) | (21.9) | |
Proved developed and undeveloped reserves, Ending Balance | 214.4 | 238.9 | 204.9 | |
Proved developed reserves | 113.9 | 125.9 | 106.2 | 75.8 |
Proved undeveloped reserves | 100.5 | 113 | 98.7 | 115.7 |
United States [Member] | Natural Gas Liquids Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 35.4 | 29.1 | 23.2 | |
Revisions of previous estimates | 1.2 | 2.2 | 5 | |
Extensions and discoveries | 2.8 | 7.6 | 4 | |
Production | (3) | (3.5) | (3.1) | |
Proved developed and undeveloped reserves, Ending Balance | 36.4 | 35.4 | 29.1 | |
Proved developed reserves | 20.8 | 20.7 | 16.5 | 13.1 |
Proved undeveloped reserves | 15.6 | 14.7 | 12.6 | 10.1 |
United States [Member] | Natural Gas Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | ft³ | 232.4 | 226.3 | 185 | |
Revisions of previous estimates | ft³ | 0.1 | (5.2) | 47.7 | |
Extensions and discoveries | ft³ | 6.4 | 43.2 | 24.1 | |
Purchases of properties | ft³ | 5.5 | |||
Sales of properties | ft³ | (0.1) | (3.7) | ||
Production | ft³ | (19.4) | (31.9) | (32.3) | |
Proved developed and undeveloped reserves, Ending Balance | ft³ | 219.4 | 232.4 | 226.3 | |
Proved developed reserves | ft³ | 138.7 | 148.3 | 145.6 | 112.6 |
Proved undeveloped reserves | ft³ | 80.7 | 84.1 | 80.7 | 72.4 |
Canada [Member] | Crude Oil [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 27.9 | 37.4 | 38.7 | |
Revisions of previous estimates | 2.5 | (4.8) | 2.7 | |
Extensions and discoveries | 2.4 | |||
Purchases of properties | 26.3 | |||
Sales of properties | (3.3) | (0.5) | ||
Production | (4.5) | (4.7) | (5.9) | |
Proved developed and undeveloped reserves, Ending Balance | 48.9 | 27.9 | 37.4 | |
Proved developed reserves | 19.2 | 23.8 | 32.4 | 31.6 |
Proved undeveloped reserves | 29.7 | 4.1 | 5 | 7.1 |
Canada [Member] | Synthetic Oil [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 114.8 | 105.6 | 117 | |
Revisions of previous estimates | 13.5 | (7) | ||
Sales of properties | (113.2) | |||
Production | (1.6) | (4.3) | (4.4) | |
Proved developed and undeveloped reserves, Ending Balance | 114.8 | 105.6 | ||
Proved developed reserves | 114.8 | 105.6 | 117 | |
Canada [Member] | Natural Gas Liquids Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 0.4 | 0.7 | 0.1 | |
Revisions of previous estimates | 0.2 | (0.3) | ||
Extensions and discoveries | 0.1 | 0.6 | ||
Purchases of properties | 5.1 | |||
Production | (0.2) | |||
Proved developed and undeveloped reserves, Ending Balance | 5.6 | 0.4 | 0.7 | |
Proved developed reserves | 0.9 | 0.3 | 0.2 | |
Proved undeveloped reserves | 4.7 | 0.1 | 0.5 | 0.1 |
Canada [Member] | Natural Gas Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | ft³ | 909.6 | 842.8 | 562.8 | |
Revisions of previous estimates | ft³ | 45.3 | 18.9 | 105.6 | |
Extensions and discoveries | ft³ | 120.2 | 119.7 | 231.5 | |
Purchases of properties | ft³ | 122.3 | |||
Sales of properties | ft³ | (2.1) | |||
Production | ft³ | (76.4) | (71.8) | (57.1) | |
Proved developed and undeveloped reserves, Ending Balance | ft³ | 1,118.9 | 909.6 | 842.8 | |
Proved developed reserves | ft³ | 498.9 | 453.5 | 467.4 | 384 |
Proved undeveloped reserves | ft³ | 620 | 456.1 | 375.4 | 178.8 |
Malaysia [Member] | Crude Oil [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 74.6 | 93.9 | 124 | |
Revisions of previous estimates | 2.6 | 4.2 | (1.8) | |
Improved recovery | 2.4 | 7.5 | ||
Extensions and discoveries | 2.4 | 7.5 | ||
Sales of properties | (11) | (23.5) | ||
Production | (13.9) | (14.9) | (19.8) | |
Proved developed and undeveloped reserves, Ending Balance | 65.7 | 74.6 | 93.9 | |
Proved developed reserves | 51.8 | 62.1 | 79.9 | 65.5 |
Proved undeveloped reserves | 13.9 | 12.5 | 14 | 58.5 |
Malaysia [Member] | Natural Gas Liquids Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | 0.6 | 0.8 | 1.1 | |
Revisions of previous estimates | 0.2 | 0.1 | 0.1 | |
Extensions and discoveries | 0.1 | |||
Sales of properties | (0.1) | (0.2) | ||
Production | (0.3) | (0.2) | (0.3) | |
Proved developed and undeveloped reserves, Ending Balance | 0.5 | 0.6 | 0.8 | |
Proved developed reserves | 0.5 | 0.6 | 0.8 | 1.1 |
Malaysia [Member] | Natural Gas Reserves [Member] | ||||
Proved developed and undeveloped oil reserves: | ||||
Proved developed and undeveloped reserves, Beginning Balance | ft³ | 546.8 | 635.6 | 405.8 | |
Revisions of previous estimates | ft³ | (2.1) | 39.8 | 13.9 | |
Improved recovery | ft³ | 1.8 | 7 | ||
Extensions and discoveries | ft³ | 37.6 | 441.2 | ||
Sales of properties | ft³ | (78) | (158.9) | ||
Production | ft³ | (42.6) | (52.4) | (73.4) | |
Proved developed and undeveloped reserves, Ending Balance | ft³ | 539.7 | 546.8 | 635.6 | |
Proved developed reserves | ft³ | 180.5 | 181.7 | 199.1 | 289.6 |
Proved undeveloped reserves | ft³ | 359.2 | 365.1 | 436.5 | 116.2 |
Supplemental Oil and Gas Inf117
Supplemental Oil and Gas Information (Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Property acquisition costs | ||||
Unproved | $ 18.6 | $ 12.6 | $ 92.9 | |
Proved | 206.7 | 7.4 | ||
Total acquisition costs | 225.3 | 12.6 | 100.3 | |
Exploration costs | [1] | 70.1 | 371.9 | 430.1 |
Development costs | [1] | 508 | 1,819.4 | 3,282.7 |
Total Costs | 803.4 | 2,203.9 | 3,813.1 | |
Charged to expense | ||||
Dry hole expense | 15.1 | 296.8 | 270 | |
Geophysical and other costs | 43.4 | 98.7 | 169.2 | |
Total charged to expense | 58.5 | 395.5 | 439.2 | |
Property additions | 744.9 | 1,808.4 | 3,373.9 | |
Exploration costs | [1] | 70.1 | 371.9 | 430.1 |
Development costs | [1] | 508 | 1,819.4 | 3,282.7 |
Total costs incurred | 803.4 | 2,203.9 | 3,813.1 | |
United States [Member] | ||||
Property acquisition costs | ||||
Unproved | 18.6 | 10.1 | 92.9 | |
Proved | 7.4 | |||
Total acquisition costs | 18.6 | 10.1 | 100.3 | |
Exploration costs | [1] | 18.5 | 166.8 | 160 |
Development costs | [1] | 239.7 | 1,375.1 | 1,934.7 |
Total Costs | 276.8 | 1,552 | 2,195 | |
Charged to expense | ||||
Dry hole expense | 0.4 | 241.3 | 92.1 | |
Geophysical and other costs | 5.7 | 16.9 | 37.7 | |
Total charged to expense | 6.1 | 258.2 | 129.8 | |
Property additions | 270.7 | 1,293.8 | 2,065.2 | |
Exploration costs | [1] | 18.5 | 166.8 | 160 |
Development costs | [1] | 239.7 | 1,375.1 | 1,934.7 |
Total costs incurred | 276.8 | 1,552 | 2,195 | |
Canada [Member] | ||||
Property acquisition costs | ||||
Unproved | 2.5 | |||
Proved | 206.7 | |||
Total acquisition costs | 206.7 | 2.5 | ||
Exploration costs | [1] | 3.6 | 0.7 | 1.7 |
Development costs | [1] | 165.1 | 231.5 | 413.8 |
Total Costs | 375.4 | 234.7 | 415.5 | |
Charged to expense | ||||
Geophysical and other costs | 3.6 | 0.7 | 1.7 | |
Total charged to expense | 3.6 | 0.7 | 1.7 | |
Property additions | 371.8 | 234 | 413.8 | |
Exploration costs | [1] | 3.6 | 0.7 | 1.7 |
Development costs | [1] | 165.1 | 231.5 | 413.8 |
Total costs incurred | 375.4 | 234.7 | 415.5 | |
Malaysia [Member] | ||||
Property acquisition costs | ||||
Exploration costs | [1] | 6 | 69 | 6.3 |
Development costs | [1] | 102.9 | 210 | 926.6 |
Total Costs | 108.9 | 279 | 932.9 | |
Charged to expense | ||||
Dry hole expense | 4.5 | 29.7 | 47.4 | |
Geophysical and other costs | 0.7 | 7.9 | 1.3 | |
Total charged to expense | 5.2 | 37.6 | 48.7 | |
Property additions | 103.7 | 241.4 | 884.2 | |
Exploration costs | [1] | 6 | 69 | 6.3 |
Development costs | [1] | 102.9 | 210 | 926.6 |
Total costs incurred | 108.9 | 279 | 932.9 | |
Other Regions [Member] | ||||
Property acquisition costs | ||||
Exploration costs | [1] | 42 | 135.4 | 262.1 |
Development costs | [1] | 0.3 | 2.8 | 7.6 |
Total Costs | 42.3 | 138.2 | 269.7 | |
Charged to expense | ||||
Dry hole expense | 10.2 | 25.8 | 130.5 | |
Geophysical and other costs | 33.4 | 73.2 | 128.5 | |
Total charged to expense | 43.6 | 99 | 259 | |
Property additions | (1.3) | 39.2 | 10.7 | |
Exploration costs | [1] | 42 | 135.4 | 262.1 |
Development costs | [1] | 0.3 | 2.8 | 7.6 |
Total costs incurred | 42.3 | 138.2 | 269.7 | |
Asset Retirement Obligation Costs [Member] | ||||
Property acquisition costs | ||||
Development costs | 13.7 | 76.8 | 70.6 | |
Total Costs | 13.7 | 76.8 | 70.6 | |
Charged to expense | ||||
Development costs | 13.7 | 76.8 | 70.6 | |
Total costs incurred | 13.7 | 76.8 | 70.6 | |
Asset Retirement Obligation Costs [Member] | United States [Member] | ||||
Property acquisition costs | ||||
Development costs | 0.9 | 30.7 | 36.5 | |
Total Costs | 0.9 | 30.7 | 36.5 | |
Charged to expense | ||||
Development costs | 0.9 | 30.7 | 36.5 | |
Total costs incurred | 0.9 | 30.7 | 36.5 | |
Asset Retirement Obligation Costs [Member] | Canada [Member] | ||||
Property acquisition costs | ||||
Development costs | 10.5 | 49.1 | (32.1) | |
Total Costs | 10.5 | 49.1 | (32.1) | |
Charged to expense | ||||
Development costs | 10.5 | 49.1 | (32.1) | |
Total costs incurred | 10.5 | 49.1 | (32.1) | |
Asset Retirement Obligation Costs [Member] | Malaysia [Member] | ||||
Property acquisition costs | ||||
Development costs | 2.3 | (3) | 66.2 | |
Total Costs | 2.3 | (3) | 66.2 | |
Charged to expense | ||||
Development costs | 2.3 | (3) | 66.2 | |
Total costs incurred | $ 2.3 | $ (3) | $ 66.2 | |
[1] | Includes noncash asset retirement costs as follows: 2016 Exploration costs$ - - - - - Development costs 0.9 10.5 2.3 - 13.7 $ 0.9 10.5 2.3 - 13.7 2015 Exploration costs$ - - - - - Development costs 30.7 49.1 (3.0) - 76.8 $ 30.7 49.1 (3.0) - 76.8 2014 Exploration costs$ - - - - - Development costs 36.5 (32.1) 66.2 - 70.6 $ 36.5 (32.1) 66.2 - 70.6 |
Supplemental Oil and Gas Inf118
Supplemental Oil and Gas Information (Results of Operations for Oil andGas Producing Activities) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Revenues | ||||||
Revenues | [1] | $ 1,799,500,000 | $ 2,775,000,000 | $ 5,273,100,000 | ||
Other operating revenues | [1] | 5,100,000 | 159,700,000 | 149,600,000 | ||
Total revenues | [1] | 1,804,600,000 | 2,934,700,000 | 5,422,700,000 | ||
Costs and expenses | ||||||
Lease operating expenses | [1] | 559,400,000 | 832,300,000 | 1,089,900,000 | ||
Severance and ad valorem taxes | [1] | 43,800,000 | 65,800,000 | 107,200,000 | ||
Exploration costs charged to expense | [1] | 58,500,000 | 395,500,000 | 439,200,000 | ||
Undeveloped lease amortization | [1] | 43,400,000 | 75,400,000 | 74,400,000 | ||
Depreciation, depletion and amortization | [1] | 1,037,300,000 | 1,607,900,000 | 1,897,500,000 | ||
Accretion of asset retirement obligations | [1] | 46,700,000 | 48,700,000 | 50,800,000 | ||
Impairment of assets | 95,088,000 | 2,493,156,000 | 51,314,000 | |||
Redetermination expense | [1] | 39,100,000 | ||||
Deepwater rig contract exit costs | (4,344,000) | 282,001,000 | ||||
Selling and general expenses | [1] | 147,400,000 | 177,200,000 | 212,000,000 | ||
Other expenses | [1] | 18,200,000 | 78,600,000 | 24,900,000 | ||
Total costs and expenses | [1] | 2,084,600,000 | 6,056,600,000 | 3,947,200,000 | ||
Results of operations before taxes | [1] | (280,000,000) | (3,121,900,000) | 1,475,500,000 | ||
Income tax expense (benefit) | [1] | (155,100,000) | (1,111,000,000) | 285,700,000 | ||
Results of operations | [1] | (124,900,000) | (2,010,900,000) | 1,189,800,000 | ||
Crude Oil and Natural Gas Liquids [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 1,506,800,000 | 2,351,500,000 | 4,587,100,000 | ||
Natural Gas [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 292,700,000 | 423,500,000 | 686,000,000 | ||
United States [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 685,800,000 | 1,247,300,000 | 2,189,300,000 | ||
Other operating revenues | [1] | (100,000) | 6,300,000 | 7,100,000 | ||
Total revenues | [1] | 685,700,000 | 1,253,600,000 | 2,196,400,000 | ||
Costs and expenses | ||||||
Lease operating expenses | [1] | 218,600,000 | 312,000,000 | 345,500,000 | ||
Severance and ad valorem taxes | [1] | 37,000,000 | 55,900,000 | 96,500,000 | ||
Exploration costs charged to expense | [1] | 6,100,000 | 258,200,000 | 129,800,000 | ||
Undeveloped lease amortization | [1] | 38,400,000 | 59,200,000 | 50,100,000 | ||
Depreciation, depletion and amortization | [1] | 600,500,000 | 794,900,000 | 840,700,000 | ||
Accretion of asset retirement obligations | [1] | 17,100,000 | 20,200,000 | 17,500,000 | ||
Impairment of assets | [1] | 329,000,000 | 14,300,000 | |||
Deepwater rig contract exit costs | [1] | (4,300,000) | 282,000,000 | |||
Selling and general expenses | [1] | 68,800,000 | 88,200,000 | 95,200,000 | ||
Other expenses | [1] | (3,200,000) | 6,700,000 | 4,900,000 | ||
Total costs and expenses | [1] | 979,000,000 | 2,206,300,000 | 1,594,500,000 | ||
Results of operations before taxes | [1] | (293,300,000) | (952,700,000) | 601,900,000 | ||
Income tax expense (benefit) | [1] | (87,900,000) | (337,000,000) | 214,800,000 | ||
Results of operations | [1] | (205,400,000) | (615,700,000) | 387,100,000 | ||
United States [Member] | Crude Oil and Natural Gas Liquids [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 650,700,000 | 1,176,900,000 | 2,062,100,000 | ||
United States [Member] | Natural Gas [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 35,100,000 | 70,400,000 | 127,200,000 | ||
Canada [Member] | ||||||
Costs and expenses | ||||||
Impairment of assets | $ 37,047,000 | 95,088,000 | 683,574,000 | 37,047,000 | [2] | |
Canada [Member] | Conventional [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 301,700,000 | 348,700,000 | 654,600,000 | ||
Other operating revenues | [1] | (700,000) | (2,400,000) | (2,400,000) | ||
Total revenues | [1] | 301,000,000 | 346,300,000 | 652,200,000 | ||
Costs and expenses | ||||||
Lease operating expenses | [1] | 102,600,000 | 102,400,000 | 160,300,000 | ||
Severance and ad valorem taxes | [1] | 4,300,000 | 4,800,000 | 5,600,000 | ||
Exploration costs charged to expense | [1] | 3,600,000 | 700,000 | 1,700,000 | ||
Undeveloped lease amortization | [1] | 4,500,000 | 14,400,000 | 19,400,000 | ||
Depreciation, depletion and amortization | [1] | 186,700,000 | 211,200,000 | 262,700,000 | ||
Accretion of asset retirement obligations | [1] | 10,900,000 | 7,200,000 | 6,000,000 | ||
Impairment of assets | [1] | 95,100,000 | 683,600,000 | 37,000,000 | ||
Selling and general expenses | [1] | 28,600,000 | 25,500,000 | 26,700,000 | ||
Other expenses | [1] | 7,500,000 | 43,900,000 | 1,000,000 | ||
Total costs and expenses | [1] | 443,800,000 | 1,093,700,000 | 520,400,000 | ||
Results of operations before taxes | [1] | (142,800,000) | (747,400,000) | 131,800,000 | ||
Income tax expense (benefit) | [1] | (58,900,000) | (191,200,000) | 42,400,000 | ||
Results of operations | [1] | (83,900,000) | (556,200,000) | 89,400,000 | ||
Canada [Member] | Synthetic Oil [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 60,700,000 | 203,000,000 | 391,500,000 | ||
Other operating revenues | [1] | 3,600,000 | 400,000 | 400,000 | ||
Total revenues | [1] | 64,300,000 | 203,400,000 | 391,900,000 | ||
Costs and expenses | ||||||
Lease operating expenses | [1] | 69,800,000 | 166,000,000 | 233,800,000 | ||
Severance and ad valorem taxes | [1] | 2,500,000 | 5,100,000 | 5,100,000 | ||
Depreciation, depletion and amortization | [1] | 16,500,000 | 50,700,000 | 54,000,000 | ||
Accretion of asset retirement obligations | [1] | 2,400,000 | 5,400,000 | 9,200,000 | ||
Selling and general expenses | [1] | 500,000 | 1,000,000 | 900,000 | ||
Total costs and expenses | [1] | 91,700,000 | 228,200,000 | 303,000,000 | ||
Results of operations before taxes | [1] | (27,400,000) | (24,800,000) | 88,900,000 | ||
Income tax expense (benefit) | [1] | (75,400,000) | 2,400,000 | 21,800,000 | ||
Results of operations | [1] | 48,000,000 | (27,200,000) | 67,100,000 | ||
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Conventional [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 171,700,000 | 181,000,000 | 453,300,000 | ||
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Synthetic Oil [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 60,700,000 | 203,000,000 | 391,500,000 | ||
Canada [Member] | Natural Gas [Member] | Conventional [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 130,000,000 | 167,700,000 | 201,300,000 | ||
Malaysia [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 751,300,000 | 976,000,000 | 2,037,700,000 | ||
Other operating revenues | [1] | 2,100,000 | 155,400,000 | 145,800,000 | ||
Total revenues | [1] | 753,400,000 | 1,131,400,000 | 2,183,500,000 | ||
Costs and expenses | ||||||
Lease operating expenses | [1] | 168,400,000 | 251,900,000 | 350,300,000 | ||
Exploration costs charged to expense | [1] | 5,200,000 | 37,600,000 | 48,700,000 | ||
Depreciation, depletion and amortization | [1] | 227,700,000 | 544,900,000 | 735,000,000 | ||
Accretion of asset retirement obligations | [1] | 16,300,000 | 15,900,000 | 18,100,000 | ||
Impairment of assets | [1] | 1,480,600,000 | ||||
Redetermination expense | [1] | 39,100,000 | ||||
Selling and general expenses | [1] | 15,900,000 | 5,700,000 | 15,700,000 | ||
Other expenses | [1] | 23,800,000 | 15,900,000 | 16,900,000 | ||
Total costs and expenses | [1] | 496,400,000 | 2,352,500,000 | 1,184,700,000 | ||
Results of operations before taxes | [1] | 257,000,000 | (1,221,100,000) | 998,800,000 | ||
Income tax expense (benefit) | [1] | 85,900,000 | (567,900,000) | 102,600,000 | ||
Results of operations | [1] | 171,100,000 | (653,200,000) | 896,200,000 | ||
Malaysia [Member] | Crude Oil and Natural Gas Liquids [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 623,700,000 | 790,600,000 | 1,680,200,000 | ||
Malaysia [Member] | Natural Gas [Member] | ||||||
Revenues | ||||||
Revenues | [1] | 127,600,000 | 185,400,000 | 357,500,000 | ||
Other Regions [Member] | ||||||
Revenues | ||||||
Other operating revenues | [1] | 200,000 | (1,300,000) | |||
Total revenues | [1] | 200,000 | (1,300,000) | |||
Costs and expenses | ||||||
Exploration costs charged to expense | [1] | 43,600,000 | 99,000,000 | 259,000,000 | ||
Undeveloped lease amortization | [1] | 500,000 | 1,800,000 | 4,900,000 | ||
Depreciation, depletion and amortization | [1] | 5,900,000 | 6,200,000 | 5,100,000 | ||
Selling and general expenses | [1] | 33,600,000 | 56,800,000 | 73,500,000 | ||
Other expenses | [1] | (9,900,000) | 12,100,000 | 2,100,000 | ||
Total costs and expenses | [1] | 73,700,000 | 175,900,000 | 344,600,000 | ||
Results of operations before taxes | [1] | (73,500,000) | (175,900,000) | (345,900,000) | ||
Income tax expense (benefit) | [1] | (18,800,000) | (17,300,000) | (95,900,000) | ||
Results of operations | [1] | $ (54,700,000) | $ (158,600,000) | $ (250,000,000) | ||
[1] | Results exclude corporate overhead, interest and discontinued operations. | |||||
[2] | This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000. |
Supplemental Oil and Gas Inf119
Supplemental Oil and Gas Information (Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 17,549.3 | $ 27,439 | $ 48,934.1 | |
Future development costs | (3,598.5) | (4,723.7) | (6,882.7) | |
Future production costs | (8,972.5) | (14,138.6) | (18,724.3) | |
Future income taxes | (273.5) | (1,060.7) | (5,569.6) | |
Future net cash flows | 4,704.8 | 7,516 | 17,757.5 | |
10% annual discount for estimated timing of cash flows | (2,124.8) | (3,656.9) | (7,852.3) | |
Standardized measure of discounted future net cash flows | 2,580 | 3,859.1 | 9,905.2 | $ 10,844.7 |
United States [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 9,477.9 | 12,373.9 | 20,767.4 | |
Future development costs | (1,691.1) | (2,620.5) | (3,151.4) | |
Future production costs | (3,981.6) | (4,955.4) | (6,378.5) | |
Future income taxes | (118.9) | (339.7) | (2,930.1) | |
Future net cash flows | 3,686.3 | 4,458.3 | 8,307.4 | |
10% annual discount for estimated timing of cash flows | (1,799.5) | (2,430) | (3,729.1) | |
Standardized measure of discounted future net cash flows | 1,886.8 | 2,028.3 | 4,578.3 | |
Canada [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 3,752.7 | 8,922 | 16,257 | |
Future development costs | (1,143.6) | (1,145.4) | (1,810.5) | |
Future production costs | (2,329.7) | (5,892.7) | (7,770.2) | |
Future income taxes | (81.3) | (504.8) | (1,389.6) | |
Future net cash flows | 198.1 | 1,379.1 | 5,286.7 | |
10% annual discount for estimated timing of cash flows | (95) | (666.8) | (2,595.3) | |
Standardized measure of discounted future net cash flows | 103.1 | 712.3 | 2,691.4 | |
Malaysia [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 4,318.7 | 6,143.1 | 11,909.7 | |
Future development costs | (763.8) | (957.8) | (1,920.8) | |
Future production costs | (2,661.2) | (3,290.5) | (4,575.6) | |
Future income taxes | (73.3) | (216.2) | (1,249.9) | |
Future net cash flows | 820.4 | 1,678.6 | 4,163.4 | |
10% annual discount for estimated timing of cash flows | (230.3) | (560.1) | (1,527.9) | |
Standardized measure of discounted future net cash flows | $ 590.1 | $ 1,118.5 | $ 2,635.5 |
Supplemental Oil and Gas Inf120
Supplemental Oil and Gas Information (Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Extractive Industries [Abstract] | ||||
Net changes in prices and production costs | $ (1,476.1) | $ (11,365.5) | $ (2,697.8) | |
Net changes in development costs | 544.9 | 591.4 | (2,317.3) | |
Sales and transfers of oil and gas produced, net of production costs | (1,196.3) | (1,876.9) | (4,076) | |
Net change due to extensions and discoveries | 280.5 | 1,145.8 | 3,251.6 | |
Net change due to purchases and sales of proved reserves | (583.4) | (287.4) | (1,041) | |
Development costs incurred | 479.6 | 1,725.4 | 3,169.3 | |
Accretion of discount | 428.1 | 1,289.5 | 1,462.5 | |
Revisions of previous quantity estimates | (49.2) | 163.3 | 518.9 | |
Net change in income taxes | 292.8 | 2,568.3 | 790.3 | |
Net increase (decrease) | (1,279.1) | (6,046.1) | (939.5) | |
Standardized measure | $ 2,580 | $ 3,859.1 | $ 9,905.2 | $ 10,844.7 |
Supplemental Oil and Gas Inf121
Supplemental Oil and Gas Information (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | $ 849 | $ 1,010.5 |
Proved oil and gas properties | 19,774 | 20,462.9 |
Gross capitalized costs | 20,623 | 21,473.4 |
Accumulated depreciation, depletion and amortization | ||
Unproved oil and gas properties | (406.6) | (462.6) |
Proved oil and gas properties | (12,049.7) | (11,338.5) |
Net capitalized costs | 8,166.7 | 9,672.3 |
Oil Reserves [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | 849 | 1,010.5 |
Proved oil and gas properties | 19,774 | 19,288.2 |
Gross capitalized costs | 20,623 | 20,298.7 |
Accumulated depreciation, depletion and amortization | ||
Unproved oil and gas properties | (406.6) | (462.6) |
Proved oil and gas properties | (12,049.7) | (10,927.8) |
Net capitalized costs | 8,166.7 | 8,908.3 |
United States [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | 360.8 | 570.3 |
Proved oil and gas properties | 9,384.6 | 9,010 |
Gross capitalized costs | 9,745.4 | 9,580.3 |
Accumulated depreciation, depletion and amortization | ||
Unproved oil and gas properties | (151.2) | (220.8) |
Proved oil and gas properties | (4,605.9) | (4,004.9) |
Net capitalized costs | 4,988.3 | 5,354.6 |
Canada [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | 315.6 | 283.1 |
Proved oil and gas properties | 4,241.6 | 4,062.2 |
Gross capitalized costs | 4,557.2 | 4,345.3 |
Accumulated depreciation, depletion and amortization | ||
Unproved oil and gas properties | (233.6) | (219.4) |
Proved oil and gas properties | (2,877.2) | (2,586) |
Net capitalized costs | 1,446.4 | 1,539.9 |
Canada [Member] | Synthetic Oil [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Proved oil and gas properties | 1,174.7 | |
Gross capitalized costs | 1,174.7 | |
Accumulated depreciation, depletion and amortization | ||
Proved oil and gas properties | (410.7) | |
Net capitalized costs | 764 | |
Malaysia [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | 47 | 28.6 |
Proved oil and gas properties | 6,147.8 | 6,216 |
Gross capitalized costs | 6,194.8 | 6,244.6 |
Accumulated depreciation, depletion and amortization | ||
Proved oil and gas properties | (4,566.6) | (4,336.9) |
Net capitalized costs | 1,628.2 | 1,907.7 |
Other Regions [Member] | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Unproved oil and gas properties | 125.6 | 128.5 |
Gross capitalized costs | 125.6 | 128.5 |
Accumulated depreciation, depletion and amortization | ||
Unproved oil and gas properties | (21.8) | (22.4) |
Net capitalized costs | $ 103.8 | $ 106.1 |
Supplemental Quarterly Infomati
Supplemental Quarterly Infomation (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Quarterly Information [Abstract] | |||||||||||
Sales and other operating revenues | $ 483,000 | $ 486,300 | $ 411,200 | $ 429,100 | $ 653,700 | $ 665,600 | $ 718,600 | $ 749,200 | $ 1,809,575 | $ 2,787,116 | $ 5,288,933 |
Income (loss) from continuing operations before income taxes | (80,100) | (16,700) | (131,300) | (265,000) | (646,500) | (2,408,000) | (110,100) | (117,700) | (493,115) | (3,282,262) | 1,252,270 |
Income (loss) from continuing operations | (62,800) | (14,600) | 2,900 | (199,500) | (583,200) | (1,587,100) | (89,000) | 3,500 | (273,943) | (2,255,772) | 1,024,973 |
Net income (loss) | $ (63,900) | $ (16,200) | $ 2,900 | $ (198,800) | $ (587,100) | $ (1,595,400) | $ (73,800) | $ (14,500) | $ (275,970) | $ (2,270,833) | $ 905,611 |
Income (loss) from continuing operations per Common share, Basic | $ (0.36) | $ (0.08) | $ 0.02 | $ (1.16) | $ (3.39) | $ (9.22) | $ (0.51) | $ 0.02 | $ (1.59) | $ (12.94) | $ 5.73 |
Income (loss) from continuing operations per Common share, Diluted | (0.36) | (0.08) | 0.02 | (1.16) | (3.39) | (9.22) | (0.51) | 0.02 | (1.59) | (12.94) | 5.69 |
Net income (loss) per Common share, Basic | (0.37) | (0.08) | 0.02 | (1.16) | (3.41) | (9.26) | (0.42) | (0.08) | (1.60) | (13.03) | 5.06 |
Net income (loss) per Common share, Diluted | (0.37) | (0.08) | 0.02 | (1.16) | (3.41) | (9.26) | (0.42) | (0.08) | (1.60) | (13.03) | 5.03 |
Cash dividend per Common share | 0.25 | 0.25 | 0.35 | 0.35 | 0.35 | 0.35 | 0.35 | 0.35 | 1.20 | 1.40 | $ 1.325 |
Market price of Common Stock, High | 34.30 | 32.66 | 36.24 | 26.69 | 31.03 | 41.42 | 50.56 | 51.77 | 36.24 | 51.77 | |
Market price of Common Stock, Low | $ 25 | $ 25.14 | $ 23.49 | $ 15.76 | $ 21.71 | $ 23.76 | $ 41.42 | $ 43.40 | $ 15.76 | $ 21.71 |
Valuation Accounts and Reser123
Valuation Accounts and Reserves (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Allowance for doubtful accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at January 1 | $ 1.6 | $ 1.6 | $ 1.6 | |
Deductions | ||||
Balance at December 31 | 1.6 | 1.6 | 1.6 | |
Deferred tax asset valuation allowance [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at January 1 | 294.4 | 306.5 | 633.7 | |
Charged (Credited) to Expense | 25.7 | 40.8 | 37.7 | |
Deductions | ||||
Other | [1] | (14.7) | (52.9) | (364.9) |
Balance at December 31 | $ 305.4 | $ 294.4 | $ 306.5 | |
[1] | Amount in 2016 for deferred tax asset valuations is primarily associated with an increase in foreign tax credit carry forwards. Amount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carry forwards. Amount in 2014 for deferred tax asset valuation allowance is primarily associated with final abandonment of certain foreign investments in 2014, essentially offsetting changes in deferred tax assets. |