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| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
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| 9805 Katy Fwy, Suite G-200 | 77024 | ||||||||||
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Page September 30, December 31, 2017 2016 ASSETS Current assets Cash and cash equivalents $ Canadian government securities with maturities greater than 90 days at – Accounts receivable, less allowance for doubtful accounts of $1,605 in Inventories, at lower of cost or market Prepaid expenses Assets held for sale Total current assets Property, plant and equipment, at cost less accumulated depreciation, Deferred income taxes Deferred charges and other assets Total assets $ LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Current maturities of long-term debt $ Accounts payable Income taxes payable Other taxes payable Other accrued liabilities Liabilities associated with assets held for sale Total current liabilities Long-term debt, including capital lease obligation Deferred income taxes Asset retirement obligations Deferred credits and other liabilities Liabilities associated with assets held for sale – Stockholders’ equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued – – Common Stock, par $1.00, authorized 450,000,000 shares, issued Capital in excess of par value Retained earnings Accumulated other comprehensive loss Treasury stock Total stockholders’ equity Total liabilities and stockholders’ equity $ Three Months Ended Nine Months Ended September 30, September 30, 2017 2016* 2017 2016* Revenues Sales and other operating revenues $ Gain (loss) on sale of assets Total revenues Costs and expenses Lease operating expenses Severance and ad valorem taxes Exploration expenses Selling and general expenses Depreciation, depletion and amortization Accretion of asset retirement obligations Impairment of assets – – – Other expense (benefit) Total costs and expenses Operating income (loss) from continuing operations Other income (loss) Interest and other income (loss) Interest expense, net Total other loss Income (loss) from continuing operations before income taxes Income tax expense (benefit) Loss from continuing operations Income (loss) from discontinued operations, NET LOSS $ INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ Discontinued operations - Net loss $ INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ Discontinued operations - Net loss $ Cash dividends per Common share Average Common shares outstanding (thousands) Basic Diluted Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Net loss $ Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation Retirement and postretirement benefit plans Deferred loss on interest rate hedges reclassified to interest Other comprehensive income (loss) COMPREHENSIVE INCOME (LOSS) $ Nine Months Ended September 30, 2017 2016 Operating Activities Net loss $ Adjustments to reconcile net loss to net cash provided by continuing operations (Income) loss from discontinued operations Depreciation, depletion and amortization Impairment of assets – Amortization of deferred major repair costs – Dry hole costs (credits) Amortization of undeveloped leases Accretion of asset retirement obligations Deferred and noncurrent income tax benefits Pretax gains from disposition of assets Net (increase) decrease in noncash operating working capital 1 Other operating activities, net Net cash provided by continuing operations activities Investing Activities Property additions and dry hole costs 2 Proceeds from sales of property, plant and equipment Purchases of investment securities3 Proceeds from maturity of investment securities3 Other investing activities, net – Net cash (required) provided by investing activities Financing Activities Borrowings of debt, net of issuance costs Repayments of debt Capital lease obligation payments Withholding tax on stock-based incentive awards Issue cost of debt facility – Cash dividends paid Other financing activities, net – Net cash required by financing activities Cash Flows from Discontinued Operations Operating activities Changes in cash included in current assets held for sale Net change in cash and cash equivalents of discontinued operations – Effect of exchange rate changes on cash and cash equivalents Net increase in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ cash flow reconciliation. See Notes to Consolidated Financial Statements, page Nine Months Ended September 30, 2017 2016 Cumulative Preferred Stock – par $100, authorized 400,000 shares, $ – – Common Stock – par $1.00, authorized 450,000,000 shares, Balance at beginning of period Exercise of stock options – – Balance at end of period Capital in Excess of Par Value Balance at beginning of period Restricted stock transactions and other Stock-based compensation Other Balance at end of period Retained Earnings Balance at beginning of period Net loss for the period Cash dividends Balance at end of period Accumulated Other Comprehensive Loss Balance at beginning of period Foreign currency translation gain, net of income taxes Retirement and postretirement benefit plans, net of income taxes Deferred loss on interest rate hedges reclassified to interest expense, Balance at end of period Treasury Stock Balance at beginning of period Sale of stock under employee stock purchase plan Awarded restricted stock, net of forfeitures Balance at end of period – 22,482,851 shares of Common Stock in Total Stockholders’ Equity $ bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer. (Thousands of dollars) 2017 2016 Beginning balance at January 1 $ Additions pending the determination of proved reserves Reclassifications to proved properties based on the determination of proved reserves – Capitalized exploratory well costs charged to expense – Other adjustments – Balance at September 30 $ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) September 30, 2017 2016 (Thousands of dollars) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Aging of capitalized well costs: Zero to one year $ $ One to two years Two to three years – Three years or more – $ $ bonus payment contingent upon certain future exploratory drilling results prior to October 2020. Three Months Nine Months Ended September 30, Ended September 30, (Thousands of dollars) 2017 2016 2017 2016 Revenues (costs) $ Income (loss) before income taxes Income tax benefit – – – – Income (loss) from discontinued operations $ September 30, December 31, (Thousands of dollars) 2017 2016 Current assets Cash $ Accounts receivable Total current assets held for sale $ Current liabilities Accounts payable $ Refinery decommissioning cost Total current liabilities associated with assets held for sale $ Non-current liabilities Asset retirement obligation - Seal asset $ – RCF. Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Nine Months Ended September 30, (Thousands of dollars) 2017 2016 Net (increase) decrease in operating working capital other than Decrease in accounts receivable $ Decrease (increase) in inventories Decrease in prepaid expenses Decrease in other – Decrease in accounts payable and accrued liabilities * (Decrease) increase in current income tax liabilities Net (increase) decrease in noncash operating working capital $ Supplementary disclosures: Cash income taxes paid, net of refunds $ Interest paid, net of amounts capitalized of $3,338 in 2017 Non-cash investing activities: Asset retirement costs capitalized $ Decrease in capital expenditure accrual Three Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2017 2016 2017 2016 Service cost $ Interest cost Expected return on plan assets – – Amortization of prior service cost (credit) Amortization of transitional asset – – – Recognized actuarial loss – Net periodic benefit expense $ Nine Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2017 2016 2017 2016 Service cost $ Interest cost Expected return on plan assets – – Amortization of prior service cost (credit) Amortization of transitional asset – – – Recognized actuarial loss – Curtailments – – Net periodic benefit expense $ Operations. Note option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the six-month period ended June 30, 2020. Nine Months Ended September 30, (Thousands of dollars) 2017 2016 Compensation charged against income (loss) before tax benefit $ Related income tax benefit recognized in income three-month and Three Months Ended Nine Months Ended September 30, September 30, (Weighted-average shares) 2017 2016 2017 2016 Basic method Dilutive stock options and restricted stock units* – – – – Diluted method Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Antidilutive stock options excluded from diluted shares Weighted average price of these options $ $ $ $ 2017 2016 Three months ended September 30 (4.3%) 13.0% Nine months ended September 30 137.7% 48.9% rate. MP GOM. 2018. Following the divestment of Malaysia in the third quarter of Foreign Currency Exchange Risks 2020 and 2019. September 30, 2017 December 31, 2016 (Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Accounts payable $ Accounts payable $ Foreign exchange Accounts receivable – Accounts payable Gain (Loss) Three Months Ended Nine Months Ended (Thousands of dollars) September 30, September 30, Type of Derivative Contract Statement of Operations Location 2017 2016 2017 2016 Commodity Sales and other operating revenues $ Foreign exchange Interest and other income (loss) – $ September 30, 2017 December 31, 2016 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee $ – – – – Commodity derivative contracts – – – – Foreign currency exchange – – – – – – $ – – Note Nine-months ended September 30, 2016 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment Level 1 Level 2 Level 3 Impairment Expense (Thousands of dollars) Assets: Impaired proved properties Canada $ – – Deferred Loss on Foreign Retirement and Interest Currency Postretirement Rate Translation Benefit Plan Derivative (Thousands of dollars) Gains (Losses) Adjustments Hedges Total Balance at December 31, 2016 $ 2017 components of other comprehensive income (loss): �� Before reclassifications to income – Reclassifications to income – 1 2 Net other comprehensive income Balance at September 30, 2017 $ (benefit) for the six-month period ended June 30, 2020. 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. Contingencies Three Months Ended Three Months Ended Total Assets September 30, 2017 September 30, 2016 at September 30, External Income External Income (Millions of dollars) 2017 Revenues (Loss) Revenues (Loss) Exploration and production* United States $ Canada Malaysia Other – Total exploration and production Corporate – Assets/revenue/loss from continuing operations Discontinued operations, net of tax – – Total $ Nine Months Ended Nine Months Ended September 30, 2017 September 30, 2016 External Income External Income (Millions of dollars) Revenues (Loss) Revenues (Loss) Exploration and production* United States $ Canada Malaysia Other – Total exploration and production Corporate Revenue/loss from continuing operations Discontinued operations, net of tax – – Total $ Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (Millions of dollars) 2017 2016 2017 2016 Exploration and production $ Corporate and other Loss from continuing operations Discontinued operations Net loss $ ITEM 2. Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (Millions of dollars) 2017 2016 2017 2016 Exploration and production United States $ Canada Malaysia Other International Total $ Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Net crude oil and condensate produced – barrels per day United States – Eagle Ford Shale – Gulf of Mexico and other Canada – onshore – offshore – heavy1 – – synthetic1 – – – Malaysia – Sarawak – Block K Net crude oil and condensate sold – barrels per day United States – Eagle Ford Shale – Gulf of Mexico and other Canada – onshore – offshore – heavy1 – – synthetic1 – – – Malaysia – Sarawak – Block K Net natural gas liquids produced – barrels per day United States – Eagle Ford Shale – Gulf of Mexico and other Canada Malaysia – Sarawak Net natural gas liquids sold – barrels per day United States – Eagle Ford Shale – Gulf of Mexico Canada Malaysia – Sarawak Net natural gas sold – thousands of cubic feet per day United States – Eagle Ford Shale – Gulf of Mexico and other Canada Malaysia – Sarawak – Block K Total net hydrocarbons produced – equivalent barrels per day2 Total net hydrocarbons sold – equivalent barrels per day2 Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Weighted average sales prices Crude oil and condensate – dollars per barrel United States – Eagle Ford Shale $ – Gulf of Mexico Canada1 – onshore – offshore – heavy2 – – synthetic2 – – – Malaysia – Sarawak3 – Block K3 Natural gas liquids – dollars per barrel United States – Eagle Ford Shale $ – Gulf of Mexico Canada1 Malaysia – Sarawak3 Natural gas – dollars per thousand cubic feet United States – Eagle Ford Shale $ – Gulf of Mexico Canada1 Malaysia – Sarawak3 – Block K United (Millions of dollars) States Canada Malaysia Other Total Three Months Ended September 30, 2017 Oil and gas sales and other operating revenues $ – Lease operating expenses – Severance and ad valorem taxes – – Depreciation, depletion and amortization Accretion of asset retirement obligations – Exploration expenses Dry holes – – Geological and geophysical – – Other – Undeveloped lease amortization – – Total exploration expenses Selling and general expenses Other expenses – Results of operations before taxes Income tax provisions (benefits) Results of operations (excluding corporate $ Three Months Ended September 30, 2016 Oil and gas sales and other operating revenues $ Lease operating expenses – Severance and ad valorem taxes – – Depreciation, depletion and amortization Accretion of asset retirement obligations – Exploration expenses Dry holes – Geological and geophysical – Other – – – Undeveloped lease amortization – – Total exploration expenses Selling and general expenses Other expenses – Results of operations before taxes Income tax provisions (benefits) Results of operations (excluding corporate $ Canada United Conven- (Millions of dollars) States tional Synthetic* Malaysia Other Total Nine Months Ended September 30, 2017 Oil and gas sales and other operating revenues $ – – Lease operating expenses – – Severance and ad valorem taxes – – – Depreciation, depletion and amortization – Accretion of asset retirement obligations – – Exploration expenses Dry holes – – – Geological and geophysical – – Other – – – Undeveloped lease amortization – – – Total exploration expenses – Selling and general expenses – Other expenses – – Results of operations before taxes – Income tax provisions (benefits) – Results of operations (excluding corporate $ – Nine Months Ended September 30, 2016 Oil and gas sales and other operating revenues $ Lease operating expenses – Severance and ad valorem taxes – – Depreciation, depletion and amortization Accretion of asset retirement obligations – Impairment of assets – – – – Exploration expenses Dry holes – – Geological and geophysical – Other – – – Undeveloped lease amortization – – Total exploration expenses – Selling and general expenses Other expenses (benefits) – – Results of operations before taxes Income tax provisions (benefits) Results of operations (excluding corporate $ Three Months Ended Nine Months Ended September 30, September 30, (Millions of dollars) 2017 2016 2017 2016 U.S. refining and marketing $ – – U.K. refining and marketing U.K. exploration and production – – Income (loss) from discontinued operations $ Net cash provided by continuing operating activities was Cash used for property additions and dry holes, which includes amounts expensed, were 2020. See Outlook section on page 36 for further details. Nine Months Ended September 30, (Millions of dollars) 2017 2016 Capital Expenditures Exploration and production $ Corporate Total capital expenditures $ Nine Months Ended September 30, (Millions of dollars) 2017 2016 Property additions and dry hole costs per cash flow statements $ Geophysical and other exploration expenses Capital expenditure accrual changes and other Total capital expenditures $ payable is due to lower capital activity. Lower accounts receivable is due to lower commodity sales prices. September 30, 2017 December 31, 2016 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ % $ % Stockholders' equity % % Total capital employed $ % $ % any general and administrative costs. The Company will primarily fund its remaining capital program in response to COVID-19 is discussed in more detail in the risk factors on page 39. Natural Gas Exchange Commission and on page By 101. INS XBRL Instance Document 101. SCH XBRL Taxonomy Extension Schema Document 101. CAL XBRL Taxonomy Extension Calculation Linkbase Document 101. DEF XBRL Taxonomy Extension Definition Linkbase Document 101. LAB XBRL Taxonomy Extension Labels Linkbase Document 101. PRE XBRL Taxonomy Extension Presentation LinkbaseSecurities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol Name of each exchange on which registered Common Stock, $1.00 Par Value MUR New York Stock Exchange Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.[X]☒ Yes [ ]☐ NoIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).[X]☒ Yes [ ]☐ No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”,filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]Emerging growth company [ ]Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). Emerging growth company [ ]Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.[ ]Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ NoNumber of shares of Common Stock, $1.00 par value, outstanding at OctoberJuly 31, 2017 2020was 172,572,873.153,598,625.MURPHYMURPHY OIL CORPORATIONTABLE OF CONTENTS23363636363636371CONSOLIDATED BALANCE SHEETS (unaudited)(Thousands of dollars)997,207 872,797
the date of acquisition111,542
2017 and 2016267,209 357,099 120,066 127,071 39,427 63,604 23,248 27,070 1,447,157 1,559,183
depletion and amortization of $12,027,902 in 2017 and $12,607,815 in 20168,283,738 8,316,188 406,703 365,935 55,161 54,554 10,192,759 10,295,860 9,781 569,817 584,025 784,975 57,687 13,920 30,160 28,167 146,607 102,777 3,270 2,776 831,530 1,502,432 2,908,285 2,422,750 108,756 69,081 747,602 681,528 616,452 617,490 85,900
195,055,724 shares in 2017 and 2016195,056 195,056 910,936 916,799 5,575,175 5,729,596 (425,504) (628,212) (1,275,529) (1,296,560) 4,980,134 4,916,679 10,192,759 10,295,860 (Thousands of dollars) June 30,
2020December 31,
2019ASSETS Current assets Cash and cash equivalents $ 145,505 306,760 Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019 372,549 426,684 Inventories 59,728 76,123 Prepaid expenses 61,271 40,896 Assets held for sale 124,337 123,864 Total current assets 763,390 974,327 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $10,603,617 in 2020 and $9,333,646 in 2019 8,891,419 9,969,743 Operating lease assets 779,591 598,293 Deferred income taxes 290,006 129,287 Deferred charges and other assets 29,624 46,854 Total assets $ 10,754,030 11,718,504 LIABILITIES AND EQUITY Current liabilities Accounts payable $ 366,205 602,096 Income taxes payable 18,646 19,049 Other taxes payable 16,988 18,613 Operating lease liabilities 103,341 92,286 Other accrued liabilities 151,848 197,447 Liabilities associated with assets held for sale 13,711 13,298 Total current liabilities 670,739 942,789 Long-term debt, including capital lease obligation 2,956,419 2,803,381 Asset retirement obligations 844,545 825,794 Deferred credits and other liabilities 628,904 613,407 Non-current operating lease liabilities 697,674 521,324 Deferred income taxes 182,267 207,198 Total liabilities 5,980,548 5,913,893 Equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, NaN issued — — Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2020 and 195,089,269 shares in 2019 195,101 195,089 Capital in excess of par value 931,429 949,445 Retained earnings 5,823,426 6,614,304 Accumulated other comprehensive loss (690,341) (574,161) Treasury stock (1,691,070) (1,717,217) Murphy Shareholders' Equity 4,568,545 5,467,460 Noncontrolling interest 204,937 337,151 Total equity 4,773,482 5,804,611 Total liabilities and equity $ 10,754,030 11,718,504 See Notes to Consolidated Financial Statements, page 7.The Exhibit Index is on page 38.2CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)(Thousands of dollars, except per share amounts)Three Months Ended
June 30,Six Months Ended
June 30,498,202 486,276 1,552,473 1,326,587 117 (730) 130,765 3,101 498,319 485,546 1,683,238 1,329,688 (Thousands of dollars, except per share amounts) (Thousands of dollars, except per share amounts) 2020 2019 2020 2019 Revenues and other income Revenues and other income Revenue from sales to customers Revenue from sales to customers $ 285,745 680,436 886,303 1,309,790 (Loss) gain on crude contracts (Loss) gain on crude contracts (75,880) 57,916 324,792 57,916 Gain on sale of assets and other income Gain on sale of assets and other income 1,677 5,598 4,175 6,790 Total revenues and other income Total revenues and other income 211,542 743,950 1,215,270 1,374,496 Costs and expenses 112,751 119,663 346,072 435,296 Lease operating expenses 144,644 137,132 353,792 268,828 10,816 9,592 32,771 35,668 Severance and ad valorem taxes 6,442 13,072 15,864 23,169 28,492 19,866 77,356 83,910 Transportation, gathering and processing Transportation, gathering and processing 41,090 34,901 85,457 74,443 Exploration expenses, including undeveloped lease amortization Exploration expenses, including undeveloped lease amortization 29,468 30,674 49,594 63,212 56,672 55,523 168,259 196,143 Selling and general expenses 39,100 57,532 75,872 120,892 Restructuring expenses Restructuring expenses 41,397 — 41,397 — 243,636 255,900 714,782 797,288 Depreciation, depletion and amortization 231,446 264,302 537,548 493,708 10,654 11,043 31,638 35,514 Accretion of asset retirement obligations 10,469 9,897 20,435 19,237 95,088 Impairment of assets 19,616 — 987,146 — 2,454 6,486 10,988 (1,446) Other (benefit) expense Other (benefit) expense 22,007 25,437 (23,181) 55,442 465,475 478,073 1,381,866 1,677,461 Total costs and expenses 585,679 572,947 2,143,924 1,118,931 32,844 7,473 301,372 (347,773) Operating (loss) income from continuing operations Operating (loss) income from continuing operations (374,137) 171,003 (928,654) 255,565 Other income (loss) (47,721) 14,987 (93,524) 38,602 Interest and other income (loss) (5,171) (8,968) (4,930) (13,716) (48,681) (39,219) (138,423) (103,889) Interest expense, net (38,598) (54,096) (79,695) (100,165) (96,402) (24,232) (231,947) (65,287) Total other loss (43,769) (63,064) (84,625) (113,881) (63,558) (16,759) 69,425 (413,060) 2,760 (2,176) 95,602 (201,897) (66,318) (14,583) (26,177) (211,163)
net of income taxes425 (1,593) 1,177 (885) (65,893) (16,176) (25,000) (212,048) (Loss) income from continuing operations before income taxes (Loss) income from continuing operations before income taxes (417,906) 107,939 (1,013,279) 141,684 Income tax (benefit) expense Income tax (benefit) expense (94,773) 9,115 (186,306) 19,937 (Loss) income from continuing operations (Loss) income from continuing operations (323,133) 98,824 (826,973) 121,747 (Loss) income from discontinued operations, net of income taxes (Loss) income from discontinued operations, net of income taxes (1,267) 24,418 (6,129) 74,264 Net (loss) income including noncontrolling interest Net (loss) income including noncontrolling interest (324,400) 123,242 (833,102) 196,011 Less: Net (loss) income attributable to noncontrolling interest Less: Net (loss) income attributable to noncontrolling interest (7,216) 30,970 (99,814) 63,557 NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY $ (317,184) 92,272 (733,288) 132,454 (LOSS) INCOME PER COMMON SHARE – BASIC (LOSS) INCOME PER COMMON SHARE – BASIC (0.38) (0.08) (0.15) (1.23) Continuing operations $ (2.05) 0.40 (4.74) 0.34 (0.01) 0.01 (0.01) Discontinued operations (0.01) 0.15 (0.04) 0.44 (0.38) (0.09) (0.14) (1.24) Net (loss) income Net (loss) income $ (2.06) 0.55 (4.78) 0.78 (LOSS) INCOME PER COMMON SHARE – DILUTED (LOSS) INCOME PER COMMON SHARE – DILUTED (0.38) (0.08) (0.15) (1.23) Continuing operations $ (2.05) 0.40 (4.74) 0.34 (0.01) 0.01 (0.01) Discontinued operations (0.01) 0.14 (0.04) 0.43 (0.38) (0.09) (0.14) (1.24) Net (loss) income Net (loss) income $ (2.06) 0.54 (4.78) 0.77 0.25 0.25 0.75 0.95 Cash dividends per Common share 0.13 0.25 0.38 0.50 Average Common shares outstanding (thousands) 172,573 172,199 172,509 172,165 Basic 153,581 168,538 153,429 170,556 172,573 172,199 172,509 172,165 Diluted 153,581 169,272 153,429 171,433 See Notes to Consolidated Financial Statements, page 7.*Reclassified to conform to current presentation (see Note A).3CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)(Thousands of dollars)(65,893) (16,176) (25,000) (212,048) 101,210 (37,369) 194,094 124,522 2,396 2,515 7,169 7,544
expense482 482 1,445 1,445 104,088 (34,372) 202,708 133,511 38,195 (50,548) 177,708 (78,537) Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2020 2019 2020 2019 Net (loss) income including noncontrolling interest $ (324,400) 123,242 (833,102) 196,011 Other comprehensive (loss) income, net of tax Net (loss) gain from foreign currency translation 50,568 28,606 (67,843) 54,055 Retirement and postretirement benefit plans (39,234) 2,762 (48,945) 5,516 Deferred loss on interest rate hedges reclassified to interest expense 309 586 608 1,171 Other comprehensive (loss) income 11,643 31,954 (116,180) 60,742 COMPREHENSIVE (LOSS) INCOME $ (312,757) 155,196 (949,282) 256,753 See Notes to Consolidated Financial Statements, page 7.7.4CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)(ThousandsSix Months Ended
June 30,(Thousands of dollars) 2020 2019 Operating Activities Net (loss) income including noncontrolling interest $ (833,102) 196,011 Adjustments to reconcile net (loss) income to net cash (required) provided by continuing operations activities: Loss (income) from discontinued operations 6,129 (74,264) Depreciation, depletion and amortization 537,548 493,708 Previously suspended exploration costs 7,677 12,901 Amortization of undeveloped leases 14,770 15,150 Accretion of asset retirement obligations 20,435 19,237 Impairment of assets 987,146 — Noncash restructuring expense 17,565 — Deferred income tax (benefit) expense (167,902) 18,001 Mark to market (gain) loss on contingent consideration (43,529) 28,890 Mark to market (gain) loss on crude contracts (173,848) (50,831) Long-term non-cash compensation 22,760 44,755 Net decrease (increase) in noncash operating working capital 1,335 (5,366) Other operating activities, net (27,605) (42,761) Net cash provided by continuing operations activities 369,379 655,431 Investing Activities Property additions and dry hole costs (537,601) (645,169) Property additions for King's Quay FPS (51,635) — Acquisition of oil and gas properties — (1,226,261) Proceeds from sales of property, plant and equipment — 16,816 Net cash required by investing activities (589,236) (1,854,614) Financing Activities Borrowings on revolving credit facility 370,000 1,075,000 Repayment of revolving credit facility (200,000) — Cash dividends paid (57,590) (85,503) Distributions to noncontrolling interest (32,400) (68,776) Early retirement of debt (12,225) — Withholding tax on stock-based incentive awards (7,247) (6,991) Debt issuance, net of cost (613) — Proceeds from term loan and other loans 371 500,000 Capital lease obligation payments (336) (335) Repurchase of common stock — (299,924) Net cash provided by financing activities 59,960 1,113,471 Cash Flows from Discontinued Operations 1Operating activities (1,202) 122,272 Investing activities 4,494 (49,798) Financing activities — (4,914) Net cash provided by discontinued operations 3,292 67,560 Cash transferred from discontinued operations to continuing operations — 48,565 Effect of exchange rate changes on cash and cash equivalents (1,358) 3,268 Net increase (decrease) in cash and cash equivalents (161,255) (33,879) Cash and cash equivalents at beginning of period 306,760 359,923 Cash and cash equivalents at end of period $ 145,505 326,044 1 Net cash provided by discontinued operations is not part of dollars)(25,000) (212,048)
activities:(1,177) 885 714,782 797,288 95,088 3,794 (1,139) 15,226 40,859 35,828 31,638 35,514 (3,567) (345,157) (130,765) (3,101) 1,070 (152,618) 192,867 9,651 819,568 280,350 (706,417) (781,668) 69,146 1,154,623 (212,661) (651,218) 320,828 712,863 (7,229) (529,104) 427,371 541,772 541,444 (550,000) (600,000) (14,687) (7,808) (7,151) (1,138) (13,971) (129,421) (163,586) (20) (159,487) (245,079) 12,134 2,830 (12,904) (2,830) (770) (5,797) 7,268 124,410 469,910 872,797 283,183 997,207 753,093 12016 balance includes payments for deepwater rig contract exit of $266.6 million.2Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.3Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.7.5CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)(Thousands of dollars)
none issued
issued 195,055,724 shares at September 30, 2017 and 2016.195,056 195,056 195,056 195,056 916,799 910,074 (26,553) (10,078) 20,767 21,918 (77) (239) 910,936 921,675 5,729,596 6,212,201 (25,000) (212,048) (129,421) (163,586) 5,575,175 5,836,567 (628,212) (704,542) 194,094 124,522 7,169 7,544
net of income taxes1,445 1,445 (425,504) (571,031) (1,296,560) (1,306,061) 145 389 20,886 8,993
2017 and 22,855,649 shares of Common Stock in 2016, at cost(1,275,529) (1,296,679) 4,980,134 5,085,588 Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2020 2019 2020 2019 Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued $ — — — — Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2020 and 195,083,364 shares at June 30, 2019 Balance at beginning of period 195,101 195,083 195,089 195,077 Exercise of stock options — — 12 6 Balance at end of period 195,101 195,083 195,101 195,083 Capital in Excess of Par Value Balance at beginning of period 924,930 924,904 949,445 979,642 Exercise of stock options, including income tax benefits — — (156) (123) Restricted stock transactions and other (636) — (33,240) (38,732) Share-based compensation 7,135 9,040 15,380 17,676 Adjustments to acquisition valuation — — — (24,519) Balance at end of period 931,429 933,944 931,429 933,944 Retained Earnings Balance at beginning of period 6,159,808 5,627,081 6,614,304 5,513,529 Net (loss) income for the period (317,184) 92,272 (733,288) 132,454 Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact — — — 116,768 Cash dividends (19,198) (42,105) (57,590) (85,503) Balance at end of period 5,823,426 5,677,248 5,823,426 5,677,248 Accumulated Other Comprehensive Loss Balance at beginning of period (701,984) (580,999) (574,161) (609,787) Foreign currency translation (loss) gain, net of income taxes 50,568 28,606 (67,843) 54,055 Retirement and postretirement benefit plans, net of income taxes (39,234) 2,762 (48,945) 5,516 Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes 309 586 608 1,171 Balance at end of period (690,341) (549,045) (690,341) (549,045) Treasury Stock Balance at beginning of period (1,691,706) (1,217,293) (1,717,217) (1,249,162) Purchase of treasury shares — (299,924) — (299,924) Awarded restricted stock, net of forfeitures 636 — 26,147 31,869 Balance at end of period – 41,512,066 shares of Common Stock in 2020 and 32,832,771 shares of Common Stock in 2019, at cost (1,691,070) (1,517,217) (1,691,070) (1,517,217) Murphy Shareholders’ Equity 4,568,545 4,740,013 4,568,545 4,740,013 Noncontrolling Interest Balance at beginning of period 212,154 377,901 337,151 368,343 Acquisition closing adjustments — — — (4,592) Net (loss) income attributable to noncontrolling interest (7,216) 30,970 (99,814) 63,557 Distributions to noncontrolling interest owners (1) (50,339) (32,400) (68,776) Balance at end of period 204,937 358,532 204,937 358,532 Total Equity $ 4,773,482 5,098,545 4,773,482 5,098,545 See Notes to Consolidated Financial Statements, page 7.7.6NOTES TO CONSOLIDATED FINANCIAL STATEMENTSThese notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.Note A – Nature of Business and Interim Financial StatementsNATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States Canada and MalaysiaCanada and conducts oil and natural gas exploration activities worldwide.In connection with the LLOG acquisition, further discussed in Note P – Acquisitions, we hold a 0.5% interest in 2 variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2020, our maximum exposure to loss was $3.5 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy'sMurphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company'sCompany’s financial position at SeptemberJune 30, 20172020 and December 31, 2016,2019, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended SeptemberJune 30, 20172020 and 2016,2019, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., 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.Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2016Company’s 2019 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 are not necessarily indicative of future results.BeginningNote B – New Accounting Principles and Recent Accounting PronouncementsAccounting Principles AdoptedFinancial Instruments– Credit Losses. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the period ended September 30, 2017,first quarter of 2020 and it did not have a material impact on its consolidated financial statements.Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.Recent Accounting PronouncementsIncome Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain reclassificationsexceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in presentation have beenaccounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. Early adoption is permitted. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.7NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note C – Revenue from Contracts with CustomersNature of Goods and ServicesThe Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into 2 key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from 3 primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.U.S. - In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.Canada - In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.In the third quarter of 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations. Operations and revised all historical periods to reflect this presentation. There was no resultant change in net income attributable to Murphy.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note C – Revenue from Contracts with Customers(Contd.)Disaggregation of RevenueThe Company now presents a separate “Operating income (loss)reviews performance based on 2 key geographical segments and between onshore and offshore sources of revenue within these geographies.For the three-month and six-month periods ended June 30, 2020, the Company recognized $285.7 million and $886.3 million, respectively, from continuing operations” subtotalcontracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and six-month periods ended June 30, 2019, the Company recognized $680.4 million and $1,309.8 million respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2020 2019 2020 2019 Net crude oil and condensate revenue United States Onshore $ 54,550 193,565 185,786 328,241 Offshore 150,253 352,281 497,225 691,944 Canada Onshore 11,527 28,031 34,910 56,972 Offshore 11,077 42,355 35,691 87,279 Other (58) 3,123 1,806 5,975 Total crude oil and condensate revenue 227,349 619,355 755,418 1,170,411 Net natural gas liquids revenue United States Onshore 3,876 8,719 9,379 16,940 Offshore 3,464 4,478 8,490 9,770 Canada Onshore 1,276 2,775 3,310 6,236 Total natural gas liquids revenue 8,616 15,972 21,179 32,946 Net natural gas revenue United States Onshore 4,090 7,340 9,648 14,914 Offshore 10,665 9,219 25,660 13,696 Canada Onshore 35,025 28,550 74,398 77,823 Total natural gas revenue 49,780 45,109 109,706 106,433 Total revenue from contracts with customers 285,745 680,436 886,303 1,309,790 (Loss) gain on crude contracts (75,880) 57,916 324,792 57,916 Gain on sale of assets and other income 1,677 5,598 4,175 6,790 Total revenue and other income $ 211,542 743,950 1,215,270 1,374,496 Contract Balances and Asset RecognitionAs of June 30, 2020, and December 31, 2019, receivables from contracts with customers, net of royalties and associated payables, on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below Operating income (loss) from continuing operations. Previously reported periods have been changed to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss)balance sheet from continuing operations, before income taxes, Losswere $101.3 million and $186.8 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13 (see Note B), the Company did not recognize any impairment losses on receivables or contract assets arising from continuing operations,customer contracts during the reporting periods.The Company has not entered into any upstream oil and gas sale contracts that have financing components as at June 30, 2020.The Company does not employ sales incentive strategies such as commissions or Net Loss.9NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note BC – Revenue from Contracts with Customers(Contd.)Performance ObligationsThe Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.As of June 30, 2020, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:Current Long-Term Contracts Outstanding at June 30, 2020 Approximate Volumes Location Commodity End Date Description U.S. Oil Q4 2021 Fixed quantity delivery in Eagle Ford 17,000 BOED U.S. Natural Gas and NGL Q1 2023 Deliveries from dedicated acreage in Eagle Ford As produced Canada Natural Gas Q4 2020 Contracts to sell natural gas at Alberta AECO fixed prices 59 MMCFD Canada Natural Gas Q4 2020 Contracts to sell natural gas at USD Index pricing 60 MMCFD Canada Natural Gas Q4 2021 Contracts to sell natural gas at USD Index pricing 10 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD Index pricing 30 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD Index pricing 38 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD Index pricing 11 MMCFD Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.Note D – Property, Plant, and EquipmentExploratory WellsUnder Financial Accounting Standards Board (FASB)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 Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.At SeptemberJune 30, 2017,2020, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4$180.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016.2019.(Thousands of dollars) 2020 2019 148,500 130,514 Beginning balance at January 1 $ 217,326 207,855 51,614 847 Additions pending the determination of proved reserves 2,328 50,307 (13,370) (8,360) Capitalized exploratory well costs charged to expense (39,519) (13,145) (3,205) 178,384 128,156 Balance at June 30 Balance at June 30 $ 180,135 245,017 The capitalized well costs charged to expense during the first nine months of 20172020 represent a charge for asset impairments (see below). The capitalized well costs charged to expense during 2019 included the Marakas-01 wellCM-1X and the CT-1X wells in Vietnam Block SK314A, offshore Malaysia11-2/11. The wells were originally drilled in which development2017.106Note BD – Property, Plant and Equipment (Contd.)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 have been capitalized. The projects are aged based on the last well drilled in the project.June 30, 2020 2019 (Thousands of dollars) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Aging of capitalized well costs: 41,609 3 2 10,563 2 2 Zero to one year $ 24,429 3 3 33,125 3 2 8,430 2 2 53,101 3 3 One to two years 30,691 2 2 61,293 1 1 43,197 1 1 31,627 2 Two to three years — — — 27,266 1 1 85,148 7 1 32,865 4 Three years or more 125,015 6 — 123,333 5 — 178,384 13 6 128,156 11 5 $ 180,135 11 5 245,017 10 4 Of the $136.8$155.7 million of exploratory well costs capitalized more than one year at SeptemberJune 30, 2017, $70.42020, $87.6 million is in Vietnam, $27.4 million is in the U.S., $25.2 million is in Brunei, $43.2and $15.5 million is in Vietnam and $23.2 million is in Malaysia.Mexico. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. DivestmentsIn 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. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $132.4 million pretax gain was reported in the first quarter of 2017 related to the sale. Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately $19.4 million. There were no gains or losses recorded related to these sales. During the second quarter 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 $739.1 million and recorded an after-tax gain of $71.7 million in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.During the second quarter 2016, a Canadian subsidiary ofJuly 2019, the Company completed a divestiture of natural gas processingits 2 subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and sales pipeline assets that support Murphy’s Montney natural gas fieldsMurphy Sarawak Oil Co., Ltd., in the Tupper area of northeastern British Columbia.a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of approximately $187.0$960.0 million was deferred and is being recognized overrecorded as part of discontinued operations on the next 19 years in the Canadian operating segment.Consolidated Statement of Operations during 2019. The Company amortized approximately $5.3does not anticipate tax liabilities related to the sales proceeds. Murphy is entitled to receive a $100.0 million and $3.4 million of the deferred gain during the nine-month periods ended September 30, 2017 and 2016, respectively. The remaining deferred gain of $185.0 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of September 30, 2017.AcquisitionsDuring the second quarterIn 2016, a Canadian subsidiary of Murphy Oil acquired a 70 percent70% operated working interest (WI) ofin Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent30% non-operated WI ofin Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the termsAs part of the joint venture, the total consideration amountstransaction, Murphy agreed to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, andpay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of SeptemberJune 30, 2017, $32.0 million2020, all of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.fully utilized. 7NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note B – Property, Plant and Equipment (Contd.)ImpairmentsDeclinesIn 2020, declines in future oil and natural gas prices (principally driven by reduced demand in early 2016response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 39) led to impairments in certain of the Company’s producing propertiesU.S. Offshore and the nine-month period in 2016 includedOther Foreign properties. The Company recorded pretax non-cashnoncash impairment charges of $95.1$987.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal. select properties.The fair values were determined by internal discounted cash flow models using estimates of future production, prices, from futures exchanges, costs and a discount raterates believed to be consistent with those used by principal market participants in the applicable region. See also The following table reflects the recognized impairments for the six months ended June 30, 2020.Six Months Ended (Thousands of dollars) June 30, 2020 U.S. $ 947,437 Other Foreign 39,709 $ 987,146 11Note J.OtherThe Company has an interest in the Kakap field in Block K Malaysia. The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others. As required by the agreements governing the field, a redetermination (unitization) review was required in 2016. In the fourth quarter 2016, the Company recorded $39.1 million in redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, PETRONAS officially approved the redetermination that reduced the Company’s working interest from 8.6% to approximately 6.7% effective April 1, 2017. The Company partially settled $21.8 million of the redetermination expense in cash in the second quarter of 2017. The Company currently expects to settle the remainder of the redetermination costs in future periods. It is possible that the final adjustment amount could be different than the current estimate. Due to the change in working interest, the future payments under a capital lease of a floating, production and storage facility in the Kakap field are lower and the Company reduced the total debt recorded on the Consolidated Balance Sheet in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.Note CE – Discontinued Operations and Assets Held for SaleThe Company has accounted for its former Malaysian exploration and production operations and its former U.K. and, U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 20162019 were as follows:598 5 853 1,454 425 (1,593) 1,177 (885) 425 (1,593) 1,177 (885) Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2020 2019 2020 2019 Revenues $ 1 159,961 4,074 355,373 Costs and expenses Lease operating expenses — 58,160 — 120,876 Depreciation, depletion and amortization — 2,345 — 33,698 Other costs and expenses (benefits) 1,268 57,401 10,203 70,481 (Loss) income before taxes (1,267) 42,055 (6,129) 130,318 Income tax expense — 17,637 — 56,054 (Loss) income from discontinued operations $ (1,267) 24,418 (6,129) 74,264 Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production operations, the U.K. refining and marketing operations and Seal operationsthe Company’s office building in CanadaEl Dorado, AR and 2 airplanes that are reflected as held for sale on the company’sCompany’s Consolidated Balance Sheets at Septemberas of June 30, 20172020 and December 31, 2016.2019.(Thousands of dollars) June 30,
2020December 31,
2019Current assets 17,030 4,126 Cash $ 30,898 25,185 6,218 22,944 Accounts receivable 425 4,834 23,248 27,070 Inventories Inventories 406 406 Prepaid expenses and other Prepaid expenses and other 814 1,882 Property, plant, and equipment, net Property, plant, and equipment, net 82,353 82,116 Deferred income taxes and other assets Deferred income taxes and other assets 9,441 9,441 Total current assets associated with assets held for sale Total current assets associated with assets held for sale 124,337 123,864 Current liabilities 605 270 Accounts payable $ 4,342 3,702 2,665 2,506 Current maturities of long-term debt (finance lease) Current maturities of long-term debt (finance lease) 720 705 Taxes payable Taxes payable 1,510 1,411 Long-term debt (finance lease) Long-term debt (finance lease) 6,889 7,240 Asset retirement obligation Asset retirement obligation 250 240 3,270 2,776 Total current liabilities associated with assets held for sale 13,711 13,298 85,900 Note C – Discontinued Operations and Assets Held for Sale (Contd.)The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the sale in January 2017. Note DF – Financing Arrangements and DebtAt SeptemberAs of June 30, 2017,2020, the Company hashad a $1.1$1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019.November 2023. At SeptemberJune 30, 2017,2020, the Company had no$170.0 million outstanding borrowings under the 2016 facility, however, there were $84.8RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. AdvancesRCF. At June 30, 2020, the interest rate in effect on borrowings under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin. Had there been any amounts borrowed under the 2016 facility at September 30, 2017, the applicable base interest rate would have been 4.50%was 1.86%. At SeptemberJune 30, 2017,2020, the Company was in compliance with all covenants related to the 2016 facility.The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.In August 2017, the Company sold $550 million2021.12Table of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025. The Company incurred transaction costs of $8.2 million on the issue of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment will be paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 2.50% notes in September 2017. The 2.50% notes had an original maturity of December 2017.In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion), with a major banking consortium that expires in August 2019. The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows. Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024. The proceeds of the $550 million notes were used 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 March 2029. Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.8 million and $136.5 million, respectively, associated with this lease at September 30, 2017.8Note EF – Financing Arrangements and Debt (Contd.)Note G – Other Financial InformationAdditional disclosures regarding cash flow activities are provided below.
cash and cash equivalents:90,614 75,841 5,869 (15,768) 25,285 122,399 720 (115,977) (376,310) (4,721) 40,500 1,070 (152,618) 25,118 (3,911)
and $3,318 in 201695,899 52,287 38,992 13,959 42,403 179,203 Six Months Ended
June 30,(Thousands of dollars) 2020 2019 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable ¹ $ 227,710 (141,793) (Increase) decrease in inventories 13,968 (617) (Increase) decrease in prepaid expenses (20,712) (12,190) Increase (decrease) in accounts payable and accrued liabilities ¹ (219,228) 147,569 Increase (decrease) in income taxes payable (403) 1,665 Net (increase) decrease in noncash operating working capital $ 1,335 (5,366) Supplementary disclosures: Cash income taxes paid, net of refunds $ (7) 79 Interest paid, net of amounts capitalized of $4.9 million in 2020 and $0 million in 2019 100,745 102,802 Non-cash investing activities: Asset retirement costs capitalized ² $ 6,342 38,396 (Increase) decrease in capital expenditure accrual 58,602 (65,830) *2016 balance included payments for deepwater rig contract exit1 Excludes receivable/payable balances relating to mark-to-market of $266.6 million.crude contracts and contingent consideration relating to acquisitions.913Note FH – Employee and Retiree Benefit PlansThe Company has defined benefit pension plans that are principally noncontributory and cover most North American full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s 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 active and retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $63.0 million due to lower discount rate and lower plan assets relative to December 31, 2019.The table that follows provides the components of net periodic benefit expense for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016.2019.Three Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2020 2019 2020 2019 2,037 2,610 427 674 Service cost $ 2,166 2,062 446 420 7,261 5,913 966 1,109 Interest cost 5,763 7,100 794 943 (8,070) (6,626) Expected return on plan assets (6,297) (6,370) — — 259 323 (18) (21) Amortization of prior service cost (credit) 183 246 — (97) 2 3,610 3,617 38 Recognized actuarial loss 4,264 3,508 — — 5,097 5,837 1,375 1,802 Net periodic benefit expense 6,079 6,546 1,240 1,266 Other - curtailment Other - curtailment 586 — (1,825) — Other - special termination benefits Other - special termination benefits 8,435 — — — Total net periodic benefit expense Total net periodic benefit expense $ 15,100 6,546 (585) 1,266 Six Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2020 2019 2020 2019 6,099 8,533 1,276 2,022 Service cost $ 4,332 4,124 893 840 20,267 20,386 2,899 3,324 Interest cost 11,554 14,251 1,588 1,888 (21,730) (21,709) Expected return on plan assets (12,641) (12,830) — — 767 963 (55) (62) Amortization of prior service cost (credit) 366 493 — (195) 4 10,673 10,864 113 Recognized actuarial loss 8,533 7,022 — — 822 (19) 16,076 19,859 4,120 5,382 Net periodic benefit expense 12,144 13,060 2,481 2,533 Other - curtailment Other - curtailment 586 — (1,825) — Other - special termination benefits Other - special termination benefits 8,435 — — �� Total net periodic benefit expense Total net periodic benefit expense $ 21,165 13,060 656 2,533 CurtailmentThe components of net periodic benefit expense, forother than the nine months ended September 30, 2016, shownservice cost, curtailment and special termination benefits components, are included in the table above, relates to restructuring activitiesline item “Interest and other income (loss)” in Consolidated Statements of Operations. The curtailment and special termination benefits components are included in the U.S. undertaken by the Companyline item “Restructuring expenses” in the first quarterConsolidated Statement of 2016.14During the nine-monthsix-month period ended SeptemberJune 30, 2017,2020, the Company made contributions of $24.0$15.3 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 20172020 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8$22.4 million.10NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)GI – Incentive PlansThe costs resulting from all share-based and cash-based incentive plans payment transactions are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.The 20122017 Annual Incentive Plan (2012(2017 Annual Plan) authorizes 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 20122017 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 2012In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2012(2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.The 2020 Long-Term Plan and the 2018 Long-Term Incentive Plan authorizes 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 (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 20122020 Long-Term Plan expires in 2022.2030. A total of 8,700,0005,000,000 shares are issuable during the life of the 20122020 Long-Term Plan, with annual grants limitedPlan. Shares issued pursuant to 1% of Common shares outstanding; allowed shares notawards granted in an earlier yearunder this Plan may be grantedshares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in future years. the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.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.The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016 andIn the first six monthsquarter of 2017. The ESPP terminated on June 30, 2017 and was not renewed by the Company.In February 2017,2020, the Committee granted stock options for 599,000 shares at an exercise price of $28.505 per share. The Black-Scholes valuation for these awards was $7.96 per option. The Committee also granted 556,000999,700 performance-basedRSU RSUs and 282,000340,600 time-based RSU in February 2017.RSUs to certain employees under the 2018 Long-Term Plan. The fair value of the performance-based RSU,RSUs, using a Monte Carlo valuation model, ranged from $24.10 to $28.28was $21.51 per unit. The fair value of the time-based RSURSUs was estimated based on the fair market value of the Company’s stock on the date of grant which was $28.505of $21.68 per share.unit. Additionally, in February 2020, the Committee granted 329,400 SAR and 154,150 units of1,152,500 cash-settled RSU (RSUC)RSUs (CRSU) to certain employees. The SAR and RSUCCRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of these SARthe CRSUs granted in February 2020 was equivalent to the stock options granted, while the initial value of RSUC was equivalent to equity-settled restricted stock units granted.$21.68. Also, in February, the Committee granted 83,220106,248 shares of time-based RSURSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee Director Plan.Directors. These sharesunits are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $28.84$22.59 per unit on date of grant.For all periods presented,All stock option exercises are non-cash transactions for the Company had noCompany. The employee receives net shares, after applicable withholding obligations, upon each stock options exercised.Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:28,264 35,948 8,695 11,796 Six Months Ended
June 30,(Thousands of dollars) 2020 2019 Compensation charged against income before tax benefit $ 10,272 30,003 Related income tax (expense) benefit recognized in income 769 4,387 1115Note HJ – Earnings per ShareNet loss(loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for thenine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016.2019. The following table reconcilesreports the weighted-average shares outstanding used for these computations.Three Months Ended June 30, Six Months Ended
June 30,(Weighted-average shares) 2020 2019 2020 2019 172,572,873 172,199,350 172,509,418 172,164,683 Basic method 153,580,758 168,537,896 153,428,666 170,555,685 Dilutive stock options and restricted stock units ¹ Dilutive stock options and restricted stock units ¹ — 734,567 — 877,007 172,572,873 172,199,350 172,509,418 172,164,683 Diluted method 153,580,758 169,272,463 153,428,666 171,432,692 *1Due to a net lossesloss recognized by the Company for allthe three-month and six-month periods presented,ended June 30, 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.antidilutive.5,257,718 5,884,201 5,578,495 5,822,036 46.46 49.00 46.86 49.82 Three Months Ended June 30, Six Months Ended
June 30,2020 2019 2020 2019 Antidilutive stock options excluded from diluted shares 2,187,235 2,927,469 2,396,920 3,066,166 Weighted average price of these options $ 39.24 $ 45.38 $ 40.83 $ 45.66 Note IK – Income TaxesThe Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss)from continuing operations before income tax expense.taxes. For the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016,2019, the Company’s effective income tax rates were as follows:2020 2019 Three months ended June 30, 22.7% 8.4% Six months ended June 30, 18.4% 14.1% The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 35% due to similar reasons. The effective tax rate for the three-month period ended SeptemberJune 30, 2017 was below2020 is higher than the U.S. statutory tax rate of 35% primarily21% principally due to a research and development tax credit in Canada, which has the tax effectimpact of expenses in foreign jurisdictions not fully deductible from losses atincreasing the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate of 35% primarily due to an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items. During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise. Note I – Income Taxes (Contd.)The effective tax rate for the three-month period ended SeptemberJune 30, 20162019 was less thanbelow the U.S. statutory tax rate primarily due to expensesan enacted future change in foreign jurisdictions for whichthe Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $13 million and no tax benefits were recognized. applied to the pre-tax income of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).The effective tax rate for the nine-monthsix-month period ended SeptemberJune 30, 20162020 was abovebelow the U.S. statutory tax rate primarilyof 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.The effective tax rate for the six-month period ended June 30, 2019 was below the statutory tax rate of 21% due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax benefits recognized relatedliability $13 million and no tax applied to the Canadian asset dispositions andpre-tax income tax benefits on investmentsof the noncontrolling interest in foreign areas. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple 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 matters. As of SeptemberJune 30, 2017,2020, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2014;2016; Canada – 2012;2015; Malaysia – 2010;2013; and United Kingdom – 2015.162019, the Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.Note L – Financial Instruments and Risk ManagementMurphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest 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. Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Lossother comprehensive loss until the anticipated transactions occur. This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.Commodity Purchase Price RisksThe Company is subject to commodity price risk related to crude oil it produces and sells. During the first nine months 2017 and 2016,At June 30, 2020, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production. Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At September 30, 2017, the Company had 22,00045,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2017through December 2020 at an average price of $50.41$56.42, and 6,0002,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018from January to December of 2021 at an average price of $51.83. $41.54. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.At SeptemberJune 30, 2017, the fair value of WTI contracts of $3.2 million was included in Accounts Payable. The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $3.2 million for the nine-month period ended September 30, 2017.At September 30, 2016,2019, the Company had 25,00020,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. At September 30, 2016, the fair valuethrough December 2019 at an average price of $63.64 and 20,000 barrels per day in WTI crude oil swap financial contracts maturing through December 2020 at an average price of $0.2 million was included in Accounts Receivable. The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016.12NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note J – Financial Instruments and Risk Management (Contd.)The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no0 foreign currency exchange short-term derivatives outstanding at SeptemberJune 30, 2017.At SeptemberJune 30, 2016, short-term derivative instruments were outstanding in Canada for approximately $25.2 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil. The fair values of open foreign currency derivative contracts were assets of $0.1 million at September 30, 2016.At September 30, 20172020 and December 31, 2016,2019, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.June 30, 2020 December 31, 2019 (Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value (3,226) (48,864) Commodity Accounts receivable $ 157,809 Accounts payable $ (33,364) (73) For the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016,2019, 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.Gain (Loss) Gain (Loss) (Thousands of dollars) Statement of Operations Location Three Months Ended June 30, Six months ended June 30, Type of Derivative Contract 2020 2019 2020 2019 (13,573) 11,871 50,365 (22,678) Commodity (Loss) gain on crude contracts $ (75,880) 57,916 $ 324,792 57,916 143 73 26,929 (13,573) 12,014 50,438 4,251 Interest Rate RisksUnder hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016, $2.22019, $0.8 million and $1.5 million, respectively, of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at SeptemberJune 30, 20172020 was $8.9$2.3 million whichand is recorded, net of income taxes of $4.8$0.6 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.7$0.8 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining three monthsremainder of 2017.2020.1317NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note JL – Financial Instruments and Risk Management(Contd.)Fair Values – RecurringThe Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. 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 carrying value of assets and liabilities recorded at fair value on a recurring basis at SeptemberJune 30, 20172020 and December 31, 20162019, are presented in the following table.June 30, 2020 December 31, 2019 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Assets: Commodity derivative contracts Commodity derivative contracts $ — 157,809 — 157,809 — — — — $ — 157,809 — 157,809 — — — — Liabilities: Commodity derivative contracts Commodity derivative contracts $ — — — — — 33,364 — 33,364
savings plans15,161 15,161 13,904 13,904 Nonqualified employee savings plans 15,703 — — 15,703 17,035 — — 17,035 3,226 3,226 48,864 48,864
derivative contracts73 73 Contingent consideration Contingent consideration — — 103,258 103,258 — — 146,787 146,787 15,161 3,226 18,387 13,904 48,937 62,841 $ 15,703 — 103,258 118,961 17,035 33,364 146,787 197,186 The fair value of WTI crude oil derivative contracts in 20172020 and 2016 was2019 were 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 dates. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and other operating revenuesGain (loss) on crude contracts in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income. Operations. 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 in the Consolidated Statements of Operations.The contingent consideration, related to 2 acquisitions in 2019 and 2018, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations. Any remaining contingent consideration payable will be due annually in years 2021 to 2026.The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no0 offsetting positions recorded at SeptemberJune 30, 20172020 and December 31, 2016.2019.14NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)J – Financial Instruments and Risk Management (Contd.)Fair Values – NonrecurringAs a result of the fall in forward commodity prices during the first nine-month period ended September 30, 2016, the Company recognized approximately $95.1 million in pretax non-cash impairment charges related to producing properties. The fair value information associated with these impaired properties is presented in the following table.71,967 167,055 95,088 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.Note KM – Accumulated Other Comprehensive LossThe components of Accumulated Other Comprehensive Lossother comprehensive loss on the Consolidated Balance Sheets at December 31, 20162019 and SeptemberJune 30, 20172020 and the changes during the nine-monthsix-month period ended SeptemberJune 30, 20172020, are presented net of taxes in the following table.(446,555) (171,305) (10,352) (628,212) 194,094 3 194,097 7,166 1,445 8,611 194,094 7,169 1,445 202,708 (252,461) (164,136) (8,907) (425,504) 18(Thousands of dollars) Foreign
Currency
Translation
Gains (Losses)Retirement
and
Postretirement
Benefit Plan
AdjustmentsDeferred
Loss on
Interest Rate
Derivative
HedgesTotal Balance at December 31, 2019 $ (353,252) (218,015) (2,894) (574,161) Components of other comprehensive income (loss): Before reclassifications to income and retained earnings (67,843) (55,707) — (123,550) Reclassifications to income — �� 6,762 ¹ 608 ² 7,370 Net other comprehensive income (loss) (67,843) (48,945) 608 (116,180) Balance at June 30, 2020 (421,095) (266,960) (2,286) (690,341) 1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 $8,987 are included in the computation of net periodic benefit expense.expense for the six-month period ended June 30, 2020. See Note GH for additional information. Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.2Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net. Related income taxes of $777 for the nine-month period ended September 30, 2017 .2 Reclassifications before taxes of $769 are included in Interest expense, net, for the six-month period ended June 30, 2020. Related income taxes of $161 are included in Income tax expense (benefit) for the six-month period ended June 30, 2020. See Note L for additional information.Note N – Environmental and Other ContingenciesThe 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,legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences andor 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.15NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note L – Environmental and Other Contingencies (Contd.)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 priorowners 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 and operational 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. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income,income/ (loss), financial condition or liquidity in a future period.During 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 area19NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note N– Environmental 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. Based on the assessments done, the Company recorded $43.9 million in Other expense during 2015 associated with the estimated costs of remediating the site. As of September 30, 2017, the Company has a remaining accrued liability of $5.8 million associated with this event. During the first nine months of 2017, the Company’s Canadian subsidiary paid approximately $130 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter. 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. The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.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,income/(loss), cash flows or liquidity.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,income/ (loss), financial condition or liquidity in a future period.Note M – CommitmentsThe Company has entered into forward sales contracts to mitigate the price risk for a portion20Note N O– Business SegmentsInformation about business segments and geographic operations is reported in the following tables.table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, miscellaneousother gains and losses (including foreign exchange gainsgains/losses and losses)realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. Certain reclassificationsTotal Assets at June 30, 2020 Three Months Ended June 30, 2020 Three Months Ended June 30, 2019 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States $ 7,363.8 228.3 (143.1) 576.7 133.0 Canada 2,184.9 59.2 (19.5) 102.0 (5.9) Other 269.2 — (9.0) 3.1 (3.4) Total exploration and production 9,817.9 287.5 (171.6) 681.8 123.7 Corporate 915.7 (76.0) (151.6) 62.2 (24.9) Assets/revenue/income (loss) from continuing operations 10,733.6 211.5 (323.2) 744.0 98.8 Discontinued operations, net of tax 20.4 — (1.2) — 24.4 Total $ 10,754.0 211.5 (324.4) 744.0 123.2 Six Months Ended June 30, 2020 Six Months Ended June 30, 2019 External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States 739.8 (839.1) 1,077.5 249.2 Canada 148.9 (26.4) 228.9 1.6 Other 1.8 (61.3) 6.0 (31.7) Total exploration and production 890.5 (926.8) 1,312.4 219.1 Corporate 324.8 99.8 62.1 (97.4) Assets/revenue/income (loss) from continuing operations 1,215.3 (827.0) 1,374.5 121.7 Discontinued operations, net of tax — (6.1) — 74.3 Total 1,215.3 (833.1) 1,374.5 196.0 1Additional details about results of oil and gas operations are presented in the table on pages 27 and 28.21Note P – AcquisitionsLLOG Acquisition:In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.The following table contains the preliminary purchase price allocations at fair value:(Thousands of dollars) LLOG
(Final)Cash consideration paid $ 1,236,165 Contingent consideration 89,444 Total purchase consideration 1,325,609 (Thousands of dollars) Fair value of Property, plant and equipment 1,356,185 Other assets 6,697 Less: Asset retirement obligations (37,273) Total net assets $ 1,325,609 The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.Results of OperationsMurphy’s Consolidated Statement of Operations for the three month period ended June 30, 2020, included additional revenues of $40.9 million and pre-tax loss of $31.6 million attributable to the acquired LLOG assets. For the six months ended June 30, 2020, additional revenues of $134.5 million and pre-tax loss of $437.9 million attributable to the acquired LLOG assets (including impairment expense of $432.9 million).Note Q – Restructuring ChargesOn May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been maderecognized and reported as Restructuring charges as part of net income in the second quarter 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and 2 airplanes are classified as held for sale. All Restructuring charges have been recorded in the Corporate segment.22NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note Q – Restructuring Charges (Contd.)The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the three months ended June 30, 2020:(Thousands of dollars) Three Months Ended
June 30, 2020Severance $ 19,867 Pension and termination benefit charges 10,913 Contract exit costs and other 10,617 Restructuring charges $ 41,397 The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at June 30, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:(Thousands of dollars) Restructuring accruals $ 23,832 Utilizations (7,169) Liability at June 30, 2020 $ 16,663 23ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSISSummaryIn the first half of 2020 the continued spread of coronavirus disease 2019 (COVID-19) has led to 2016 disruption in the global economy and a weakness in demand for crude oil. Additionally, certain major global suppliers of crude oil announced supply increases in the first quarter of 2020 which resulted in a contribution to the lower global commodity prices in the first quarter and early second quarter. Subsequent to the supply increases the OPEC+ group of oil producing countries agreed to supply restrictions which helped support the oil price in the latter part of the second quarter. The reduction in commodity prices compared to 2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 36. Low oil demand continues.For the three months ended June 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $28 per barrel (compared to $46 in the first quarter of 2020 and $60 in the second quarter of 2019). The closing price for WTI at the end of the second quarter of 2020 was approximately $38 per barrel, reflecting a 36% reduction from the price at the end of 2019. The average price in July 2020 was $40.77 per barrel. As of August 4, 2020 closing, the NYMEX WTI forward curve price for September through December 2020 was $42.07 per barrel.For the three months ended June 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $179.6 million in capital expenditures (on a value of work done basis) in the second quarter of 2020, which included $32.7 million to fund the development of the King’s Quay Floating Production System (FPS). The Company reported net loss from continuing operations of $323.1 million (which includes loss attributable to noncontrolling interest of $7.2 million) for the second quarter of 2020.For the six months ended June 30, 2020, the Company produced 189 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $557.6 million in capital expenditures (on a value of work done basis) in the six months ended June 30, 2020, which included $61.4 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $827.0 million (which includes post tax impairment charges of $708.3 million and loss attributable to noncontrolling interest of $99.8 million) for the six months ended June 30, 2020.For the three months ended June 30, 2019, the Company produced 171 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $1.6 billion in capital expenditures (on a value of work done basis) in the second quarter of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $98.8 million (which includes income attributable to noncontrolling interest of $31.0 million) for the three months ended June 30, 2019.For the six months ended June 30, 2019, the Company produced 166 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations which excludes Malaysia as it is held for sale. The Company invested $2.0 billion in capital expenditures (on a value of work done basis) in the first half of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $121.7 million (which includes income attributable to noncontrolling interest of $63.6 million) for the six months ended June 30, 2019.During the three-month and six-month periods ended June 30, 2020, crude oil and condensate volumes from continuing operations were higher than the prior year period as a result of the LLOG acquisition in the second quarter of 2019. The additional income from higher volumes was offset by lower average oil prices that were below average comparable benchmark prices during 2019. The results are explained in more detail below.Results of OperationsMurphy’s income (loss) by type of business is presented below.Income (Loss) Three Months Ended June 30, Six Months Ended June 30, (Millions of dollars) 2020 2019 2020 2019 Exploration and production $ (171.6) 123.7 (926.8) 219.1 Corporate and other (151.6) (24.9) 99.8 (97.4) (Loss) income from continuing operations (323.2) 98.8 (827.0) 121.7 Discontinued operations ¹ (1.2) 24.4 (6.1) 74.3 Net (loss) income including noncontrolling interest $ (324.4) 123.2 (833.1) 196.0 241 The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. Exploration and ProductionResults of E&P continuing operations are presented by geographic segment below.Income (Loss) Three Months Ended
June 30,Six Months Ended June 30, (Millions of dollars) 2020 2019 2020 2019 Exploration and production United States $ (143.1) 133.0 (839.1) 249.2 Canada (19.5) (5.9) (26.4) 1.6 Other (9.0) (3.4) (61.3) (31.7) Total $ (171.6) 123.7 (926.8) 219.1 25ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Other key performance metricsThe Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net (loss) income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.Three Months Ended
June 30,Six Months Ended
June 30,(Millions of dollars, except per barrel of oil equivalents sold) 2020 2019 2020 2019 Net (loss) income attributable to Murphy (GAAP) $ (317.1) 92.3 (733.2) 132.5 Income tax (benefit) expense (94.8) 9.1 (186.3) 19.9 Interest expense, net 38.6 54.1 79.7 100.2 Depreciation, depletion and amortization expense ¹ 219.1 246.0 505.3 458.1 EBITDA attributable to Murphy (Non-GAAP) (154.2) 401.5 (334.5) 710.7 Impairment of assets ¹ 19.6 — 886.0 — Mark-to-market (gain) loss on crude oil derivative contracts 184.5 (50.8) (173.8) (50.8) Mark-to-market (gain) loss on contingent consideration 15.7 15.4 (43.5) 28.9 Restructuring expenses 41.4 — 41.4 — Accretion of asset retirement obligations 10.5 9.9 20.4 19.2 Discontinued operations loss (income) 1.2 (24.4) 6.1 (74.3) Inventory loss — — 4.8 — Foreign exchange (gains) losses 1.4 3.0 (3.3) 5.6 Unutilized rig charges 4.5 — 8.0 — Business development transaction costs — 7.8 — 20.3 Write-off of previously suspended exploration wells — — — 13.2 Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 124.6 362.4 411.6 672.8 Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 15,242 14,269 32,312 27,766 Adjusted EBITDA per barrel of oil equivalents sold 8.17 25.40 12.74 24.23 1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.26ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2020 AND 2019(Millions of dollars) UnitedStates 1Canada Other Total Three Months Ended June 30, 2020 Oil and gas sales and other operating revenues $ 228.3 59.2 — 287.5 Lease operating expenses 116.8 27.4 0.5 144.7 Severance and ad valorem taxes 6.1 0.4 — 6.5 Transportation, gathering and processing 31.5 9.6 — 41.1 Depreciation, depletion and amortization 175.8 49.7 0.5 226.0 Impairments of assets 19.6 — — 19.6 Accretion of asset retirement obligations 9.1 1.3 — 10.4 Exploration expenses Dry holes and previously suspended exploration costs 7.6 — — 7.6 Geological and geophysical 8.0 0.1 0.5 8.6 Other exploration 2.9 0.1 3.0 6.0 18.5 0.2 3.5 22.2 Undeveloped lease amortization 4.8 — 2.4 7.2 Total exploration expenses 23.3 0.2 5.9 29.4 Selling and general expenses 7.6 5.4 2.3 15.3 Other 24.2 (1.2) 0.1 23.1 Results of operations before taxes (185.7) (33.6) (9.3) (228.6) Income tax provisions (benefits) (42.6) (14.1) (0.3) (57.0) Results of operations (excluding Corporate segment) $ (143.1) (19.5) (9.0) (171.6) Three Months Ended June 30, 2019 Oil and gas sales and other operating revenues $ 576.7 102.0 3.1 681.8 Lease operating expenses 99.7 36.9 0.6 137.2 Severance and ad valorem taxes 12.8 0.3 — 13.1 Transportation, gathering and processing 27.7 7.2 — 34.9 Depreciation, depletion and amortization 201.2 56.8 1.3 259.3 Accretion of asset retirement obligations 8.4 1.5 — 9.9 Exploration expenses Dry holes and previously suspended exploration costs (0.2) — — (0.2) Geological and geophysical 15.4 — 2.4 17.8 Other exploration 2.8 0.1 3.1 6.0 18.0 0.1 5.5 23.6 Undeveloped lease amortization 5.9 0.4 0.9 7.2 Total exploration expenses 23.9 0.5 6.4 30.8 Selling and general expenses 12.9 6.1 6.1 25.1 Other 27.9 0.2 0.1 28.2 Results of operations before taxes 162.2 (7.5) (11.4) 143.3 Income tax provisions (benefits) 29.2 (1.6) (8.0) 19.6 Results of operations (excluding Corporate segment) $ 133.0 (5.9) (3.4) 123.7 1 Includes results attributable to a noncontrolling interest in MP GOM.27ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2020 AND 2019(Millions of dollars) United
States 1Canada Other Total Six Months Ended June 30, 2020 Oil and gas sales and other operating revenues $ 739.8 148.9 1.8 890.5 Lease operating expenses 295.0 58.0 0.8 353.8 Severance and ad valorem taxes 15.2 0.7 — 15.9 Transportation, gathering and processing 66.1 19.4 — 85.5 Depreciation, depletion and amortization 423.3 101.7 1.0 526.0 Impairment of assets 947.4 — 39.7 987.1 Accretion of asset retirement obligations 17.7 2.7 — 20.4 Exploration expenses Dry holes and previously suspended exploration costs 7.7 — — 7.7 Geological and geophysical 9.3 0.1 4.2 13.6 Other exploration 3.7 0.3 9.5 13.5 20.7 0.4 13.7 34.8 Undeveloped lease amortization 9.9 0.2 4.6 14.7 Total exploration expenses 30.6 0.6 18.3 49.5 Selling and general expenses 11.3 9.8 3.9 25.0 Other (21.5) (1.0) (1.1) (23.6) Results of operations before taxes (1,045.3) (43.0) (60.8) (1,149.1) Income tax provisions (benefits) (206.2) (16.6) 0.5 (222.3) Results of operations (excluding Corporate segment) $ (839.1) (26.4) (61.3) (926.8) Six months ended June 30, 2019 Oil and gas sales and other operating revenues $ 1,077.5 228.9 6.0 1,312.4 Lease operating expenses 192.1 75.9 0.9 268.9 Severance and ad valorem taxes 22.6 0.6 — 23.2 Transportation, gathering and processing 59.3 15.2 — 74.5 Depreciation, depletion and amortization 365.1 116.3 2.3 483.7 Accretion of asset retirement obligations 16.2 3.0 — 19.2 Exploration expenses Dry holes and previously suspended exploration costs (0.1) — 13.1 13.0 Geological and geophysical 15.9 — 7.9 23.8 Other exploration 4.0 0.2 7.1 11.3 19.8 0.2 28.1 48.1 Undeveloped lease amortization 12.8 0.7 1.7 15.2 Total exploration expenses 32.6 0.9 29.8 63.3 Selling and general expenses 30.2 13.7 11.7 55.6 Other 58.5 0.4 0.4 59.3 Results of operations before taxes 300.9 2.9 (39.1) 264.7 Income tax provisions (benefits) 51.7 1.3 (7.4) 45.6 Results of operations (excluding Corporate segment) $ 249.2 1.6 (31.7) 219.1 1 Includes results attributable to a noncontrolling interest in MP GOM.28ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Exploration and ProductionSecond quarter 2020 vs. 2019All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.United States E&P operations reported a loss of $143.1 million in the second quarter of 2020 compared to income of $133.0 million in the second quarter of 2019. Results were $276.1 million unfavorable in the 2020 quarter compared to the 2019 period due to lower revenues ($348.4 million), impairment charge ($19.6 million), higher lease operating expenses ($17.1 million) and transportation, gathering, and processing expenses ($3.8 million), partially offset by lower income tax expense ($71.8 million), depreciation, depletion and amortization ($25.4 million), general and administrative (G&A: $5.3 million), and other operating expense ($3.7 million). Lower revenues were primarily due to lower commodity prices and lower Eagle Ford Shale volumes (due to lower capital expenditures), partially offset by higher volumes in the U.S. Gulf of Mexico (as a result of the LLOG acquisition in the second quarter of 2019 and partially offset by shut-in GOM production in May 2020 due to the low price). The impairment charge relates to a US Offshore project for which the lease expired in June 2020. Higher lease operating expense was primarily attributable to well workovers at Dalmatian ($20.5 million) and Cascade 4 ($4.6 million), offset by certain cost-savings initiatives taken in the US Onshore business. Lower depreciation expense was primarily due to lower depreciation rates following the impairment charges incurred in the first quarter of 2020.Canadian E&P operations reported a loss of $19.5 million in the second quarter 2020 compared to a loss of $5.9 million in the 2019 quarter. Results were unfavorable $13.6 million compared to the 2019 period primarily due to lower revenue ($42.8 million), partially offset by a higher tax benefit ($12.5 million), lower lease operating expenses ($9.5 million) and lower depreciation and amortization ($7.1 million). Lower revenue was principally due to lower commodity prices and lower Terra Nova volumes, partially offset by higher volumes at Kaybob and Hibernia. Lower lease operating expenses and depreciation were a result of a shut-in at Terra Nova (starting in December 2019). Terra Nova is expected to be shut-in for the remainder of 2020 for Asset Integrity work.Other international E&P operations reported a loss from continuing operations of $9.0 million in the second quarter of 2020 compared to a net a loss of $3.4 million in the prior year quarter. The result was $5.6 million unfavorable in the 2020 period versus 2019 primarily due higher Brunei prior period revenue.Six months 2020 vs. 2019All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.United States E&P operations reported a loss of $839.1 million in the first six months of 2020 compared to income of $249.2 million in the first six months of 2019. Results were $1,088.3 million unfavorable in the 2020 quarter compared to the 2019 period primarily due to an impairment charge ($947.4 million), lower revenues ($337.7 million), higher lease operating expenses ($102.9 million), depreciation, depletion and amortization (DD&A: $58.2 million), and transportation, gathering, and processing charges ($6.8 million); partially offset by lower income tax expense ($257.9 million), other operating expense ($80.0 million), and G&A ($18.9 million). The impairment charge is a result of lower forecast future prices at the end of the first quarter 2020, as a result of decreased oil demand and increased oil supply (as discussed above). Based on an evaluation of expected future cash flows from properties as of June 30, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recorded in the future. Higher lease operating expenses and depreciation expense were due primarily to higher volumes from the LLOG acquisition in the second quarter of 2019 ($21.9 million) and well workovers at Cascade ($49.3 million) and Dalmatian ($20.5 million). Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration from prior Gulf of Mexico (GOM) acquisitions ($43.5 million). Lower G&A is due to lower long-term incentive charges. Lower revenues were primarily due to lower commodity prices partially offset by higher volumes in the U.S. Gulf of Mexico (as a result of the LLOG acquisition in the second quarter of 2019).Canadian E&P operations reported a loss of $26.4 million in the first six months of 2020 compared to income of $1.6 million in the first six months quarter of 2019. Results were unfavorable $28 million compared to the 2019 period primarily due to lower revenue ($80.0 million), partially offset by lower lease operating expense ($17.9 million), lower DD&A ($14.6 million), and lower income tax charges ($17.9 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue through 2020 full year). Lower lease operating expenses and lower DD&A were a result of lower sales.29ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Other international E&P operations reported a loss from continuing operations of $61.3 million in the first six months of 2020 compared to a net loss of $31.7 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.CorporateSecond quarter 2020 vs. 2019On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income in the second quarter 2020. These costs include severance, relocation, IT costs, pension curtailment, termination charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale.Corporate External Revenueactivities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to alignExploration and Production, reported a net loss of $151.6 million in the second quarter 2020 compared to net loss of $24.9 million in the 2019 quarter. The $126.7 million unfavorable variance is principally due to 2020 mark to market losses on forward swap commodity contracts ($184.5 million) compared to gains on forward contracts ($50.8 million) in the second quarter of 2019, restructuring charges ($41.4 million) related to the closure of the El Dorado and Calgary offices, offset by higher realized gains on forward commodity contracts ($101.5 million), higher tax credit ($27.4 million), lower interest expense ($15.6 million) and G&A expenses ($8.6 million). Losses in forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with currenta fixed price. Higher realized gains on forward commodity contracts are due to lower prices versus the fixed contract price. Lower interest expense is due to higher borrowings in the second quarter 2019 due to temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the revolver borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business).Six months 2020 vs. 2019Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported earnings of $99.8 million in the first six months of 2020 compared to a loss of $97.4 million in the first six months of 2019. The $197.2 million favorable variance is primarily due to higher mark to market gains on forward swap commodity contracts ($123.0 million), higher realized gains on forward swap commodity contracts ($143.9 million), lower interest charges ($24.1 million), lower G&A ($14.4 million), and partially offset by higher tax charges ($61.7 million) and restructuring charges ($41.4 million). As of June 30, 2020, the average forward NYMEX WTI price for the remainder of 2020 was $39.47 and for 2021 was $40.31 (versus fixed hedge prices of $56.42 and $42.93; see below).30ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Production Volumes and PricesSecond quarter 2020 vs. 2019Total hydrocarbon production from continuing operations averaged 179,506 barrels of oil equivalent per day in the second quarter of 2020, which represented a 5% increase from the 170,885 barrels per day produced in second quarter 2019. The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019, partially offset by GOM shut-in production in May 2020 (32.4 MBOED) for low commodity prices and lower Eagle Ford Shale production.Average crude oil and condensate production from continuing operations was 108,712 barrels per day in the second quarter of 2020 compared to 107,283 barrels per day in the second quarter of 2019. The increase of 1,429 barrels per day was principally due to higher volumes in the Gulf of Mexico (5,940 barrels per day) due to the acquisition of assets as part of the LLOG acquisition and offset by GOM shut-in production in May 2020 (20 MBOED) for low commodity prices and lower Eagle Ford Shale production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $23.03 per barrel in the second quarter 2020 compared to $64.74 per barrel in the 2019 period, presentation (see Note A)a decrease of 64% quarter to quarter.Total production of natural gas liquids (NGL) from continuing operations was 11,540 barrels per day in the second quarter 2020 compared to 10,168 barrels per day in the 2019 period. The average sales price for U.S. NGL was $7.67 per barrel in the 2020 quarter compared to $15.95 per barrel in 2019. The average sales price for NGL in Canada was $13.78 per barrel in the 2020 quarter compared to $28.41 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.Natural gas sales volumes from continuing operations averaged 356 million cubic feet per day (MMCFD) in the second quarter 2020 compared to 321 MMCFD in 2019. The increase of 35 MMCFD was a result of higher volumes in the Gulf of Mexico (30 MMCFD) and higher volumes in Canada (10 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.5,439.1 195.9 (19.9) 201.8 (27.1) 1,711.1 81.9 (3.2) 80.9 (4.8) 1,755.3 220.5 67.7 202.7 65.0 139.9 (11.0) 0.2 (8.1) 9,045.4 498.3 33.6 485.6 25.0 1,124.2 (99.9) (0.1) (39.6) 10,169.6 498.3 (66.3) 485.5 (14.6) 23.2 0.4 (1.6) 10,192.8 498.3 (65.9) 485.5 (16.2) 696.7 11.0 520.2 (158.5) 388.1 102.6 264.4 (36.9) 594.4 173.9 541.4 135.1 (10.9) 0.2 (39.2) 1,679.2 276.6 1,326.2 (99.5) 4.0 (302.8) 3.5 (111.7) 1,683.2 (26.2) 1,329.7 (211.2) 1.2 (0.8) 1,683.2 (25.0) 1,329.7 (212.0) *Six months 2020 vs. 2019Total hydrocarbon production from all E&P continuing operations averaged 189,350 barrels of oil equivalent per day in the first six months of 2020, which represented a 14% increase from the 166,269 barrels per day produced in the first six months of 2019. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.Average crude oil and condensate production from continuing operations was 115,396 barrels per day in the first six months of 2020 compared to 104,567 barrels per day in the first six months of 2019. The increase of 10,829 barrels per day was principally due to higher volumes in the Gulf of Mexico (11,811 barrels per day) due to the acquisition of assets as part of the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $35.65 per barrel in the first six months of 2020 compared to $61.83 per barrel in the 2019 period, a decrease of 42% year over year.Total production of natural gas liquids (NGL) from continuing operations was 12,597 barrels per day in the first six months of 2020 compared to 9,664 barrels per day in the 2019 period. The average sales price for U.S. NGL was $8.62 per barrel in 2020 compared to $17.20 per barrel in 2019. The average sales price for NGL in Canada was $15.04 per barrel in 2020 compared to $31.81 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.Natural gas sales volumes from continuing operations averaged 368 million cubic feet per day (MMCFD) in the first six months of 2020 compared to 312 MMCFD in 2019. The increase of 56 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (46 MMCFD) and the Canadian Tupper asset (20 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the LLOG transaction. Higher volumes at the Tupper asset are due to higher number of wells operating and improved type curves.Natural gas prices for the total Company averaged $1.64 per thousand cubic feet (MCF) in the first six months of 2020, versus $1.88 per MCF average in the same period of 2019. Average natural gas prices in the US and Canada in the quarter were $1.84 and $1.55, respectively.Additional details about results of oil and gas operations are presented in the tables on pages 2927 and 30.Note O – New Accounting Principles AdoptedBusiness CombinationsIn January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition28.31During the three-month and nine-month periods ended September 30, 2017, worldwide benchmark oil and natural gas prices were above average comparable benchmark prices during 2016. Although prices were above 2016 levels, unrealized losses from foreign exchange movements along with higher tax expense on earnings of foreign subsidiaries more than offset this increase in revenue in the third quarter.For the three months ended September 30, 2017, the Company produced 154 thousand barrels of oil equivalent per day. There was no production in the 2017 quarter from Canadian synthetic and heavy oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively. The Company invested $287 million in capital expenditure in the third quarter of 2017 primarily in the United States and Canada. The Company reported a net loss of $65.9 million, for the three months ended September 30, 2017, which included a foreign exchange after-tax loss of $43.9 million, principally on intercompany loans in the quarter and an after-tax loss of $11.8 million in the third quarter relating to crude oil derivative contracts.For the nine-month period ended September 30, 2017, the Company reported a net loss of $25.0 million, which included an after-tax gain of $96.0 million on the sale of the Seal heavy oil property in Canada. The Company produced 162 thousand barrels of oil equivalent per day for the nine-month 2017 period and invested $702 million in capital expenditures, principally in the United States and Canada. The Company incurred a non-cash deferred tax expense in the first nine months of 2017 of $65.2 million on earnings of foreign subsidiaries, the majority of which was recorded in first quarter of 2017 and recorded a foreign exchange after-tax loss of $86.6 million, principally on intercompany loans in the first nine months of 2017. Further detail and discussion is provided in the narrative below.Results of OperationsMurphy’s income (loss) by type of business is presented below.33.6 25.0 276.6 (99.5) (99.9) (39.6) (302.8) (111.7) (66.3) (14.6) (26.2) (211.2) 0.4 (1.6) 1.2 (0.8) (65.9) (16.2) (25.0) (212.0) Third quarter 2017 vs. 2016For the third quarter of 2017, Murphy’s net loss was $65.9 million ($0.38 per diluted share) compared to net loss of $16.2 million ($0.09 per diluted share) in the third quarter of 2016. Loss from continuing operations fell lower from a loss of $14.6 million ($0.08 per diluted share) in the 2016 quarter to a loss of $66.3 million ($0.38 per diluted share) in the 2017 period. The Company’s exploration and production (E&P) continuing operations earned $33.6 million in the 2017 quarter compared to earnings of $25.0 million in the 2016 quarter. The E&P results in the 2017 quarter were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices, lower lease operating expenses, lower depreciation expense and lower dry hole costs, partially offset by lower volume sold, higher selling and general expenses and higher deferred tax expense on earnings of foreign subsidiaries. The corporate function had after-tax costs of $99.9 million in the 2017 third quarter compared to after-tax costs of $39.6 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs in the current quarter. The third quarter of 2017 included gains from discontinued operations of $0.4 million ($0.00 per diluted share) compared to losses from discontinued operations of $1.6 million ($0.01 per diluted share) in the third quarter of 2016.Nine months 2017 vs. 2016For the first nine months of 2017, Murphy’s net loss was $25.0 million ($0.14 per diluted share) compared to a net loss of $212.0 million ($1.24 per diluted share) for the same period in 2016. Loss from continuing operations improved from a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016 to a loss of $26.2 million ($0.15 per diluted share) in 2017. In the first nine months of 2017, the Company’s E&P continuing operations earned $276.6 million compared to a loss of $99.5 million in the same period of 2016. The results for the first nine months of 2017 were favorably impacted19MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Nine months 2017 vs. 2016 (contd.)by higher revenues due to higher realized oilThe following table contains hydrocarbons produced during the three-month and natural gas sales prices, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, lower sellingsix-month periods ended June 30, 2020 and general expenses, lower dry hole costs and higher tax benefits on investments in foreign areas, partially offset by higher non-cash deferred tax expense on earnings of foreign subsidiaries, higher other expense related primarily to rig demobilization in Malaysia and lower oil and natural gas volume sold. The corporate function had after-tax costs of $302.8 million in the first nine months of 2017 compared to after-tax costs of $111.7 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher2019.Three Months Ended
June 30,Six Months Ended
June 30,Barrels per day unless otherwise noted 2020 2019 2020 2019 Continuing operations Net crude oil and condensate United States Onshore 27,986 33,145 29,510 29,532 Gulf of Mexico 167,002 61,062 72,866 61,055 Canada Onshore 7,872 5,943 7,353 6,199 Offshore 5,852 6,685 5,495 7,304 Other — 448 172 477 Total net crude oil and condensate - continuing operations 108,712 107,283 115,396 104,567 Net natural gas liquids United States Onshore 5,303 5,977 5,444 5,641 Gulf of Mexico 15,219 3,118 5,944 2,940 Canada Onshore 1,018 1,073 1,209 1,083 Total net natural gas liquids - continuing operations 11,540 10,168 12,597 9,664 Net natural gas – thousands of cubic feet per day United States Onshore 27,697 32,209 29,830 30,752 Gulf of Mexico 168,717 39,029 75,333 29,356 Canada Onshore 259,108 249,367 262,978 252,120 Total net natural gas - continuing operations 355,522 320,605 368,141 312,228 Total net hydrocarbons - continuing operations including NCI 2,3179,506 170,885 189,350 166,269 Noncontrolling interest Net crude oil and condensate – barrels per day (10,719) (11,160) (11,370) (11,669) Net natural gas liquids – barrels per day (443) (458) (501) (506) Net natural gas – thousands of cubic feet per day (4,059) (4,507) (4,575) (4,203) Total noncontrolling interest (11,839) (12,369) (12,634) (12,876) Total net hydrocarbons - continuing operations excluding NCI 2,3167,667 158,516 176,716 153,394 Discontinued operations Net crude oil and condensate – barrels per day — 21,556 — 23,744 Net natural gas liquids – barrels per day — 529 — 636 Net natural gas – thousands of cubic feet per day 2— 93,382 — 97,465 Total discontinued operations — 37,649 — 40,624 Total net hydrocarbons produced excluding NCI 2,3167,667 196,165 176,716 194,018 1 Includes net interest expense and non-cash deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs. Income from discontinued operations was $1.2 million ($0.01 per diluted share) in the first nine months of 2017 comparedvolumes attributable to a loss of $0.8 million ($0.01 per diluted share)noncontrolling interest in the 2016 period.Exploration and ProductionResults of E&P continuing operations are presented by geographic segment below.(19.9) (27.1) 11.0 (158.5) (3.2) (4.8) 102.6 (36.9) 67.7 65.0 173.9 135.1 (11.0) (8.1) (10.9) (39.2) 33.6 25.0 276.6 (99.5) Third quarter 2017 vs. 2016United States E&P operations reported a net loss of $19.9 million in the third quarter of 2017 compared to a net loss of $27.1 million in the 2016 quarter. Results improved $7.2 million in the 2017 quarter compared to the 2016 period. Higher oil and natural gas realized sales prices more than offset impacts of lower volumes sold. Lease operating expenses decreased due to lower costs in Eagle Ford Shale compared to the same quarter in 2016 with most of the reduction due to the Company’s continuous focus on improving its cost structure. Depreciation expense decreased in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale andMP Gulf of Mexico, and lower average unit rates in the Gulf of Mexico in the 2017 period. Amortization of undeveloped leases were higher in the 2017 quarter due to costs related to certain offshore leases expiring in 2017 and 2018. Revenue in the U.S. decreased by $5.9 million in the period as the U.S. segment recorded $18.1 million unrealized losses on open crude oil contracts in 2017 versus losses of $1.3 million in the 2016 period. This was offset in part by higher oil and gas sales revenue. Selling and general expenses increased in the third quarter of 2017 primarily due to higher allocated benefit costs in the current period versus 2016.Canadian E&P operations reported a net loss of $3.2 million in the third quarter 2017 compared to a loss of $4.8 million in the 2016 quarter. Canadian results of operations improved $1.6 million in the 2017 quarter compared to the 2016 period due to higher average sales prices received in 2017 for both oil and natural gas and lower lease operating expenses, partially offset by non-recurring 2016 income tax benefits associated with divestiture of Montney midstream assets in 2016 and a gain on sale of its synthetic operations completed in the third quarter 2016. Natural gas sales volumes increased in 2017 due to new production in the Kaybob Duvernay and Placid Montney areas of Western Canada.Malaysia E&P operations reported earnings of $67.7 million in the third quarter of 2017 and compared to earnings of $65.0 million in the comparable 2016 period. Results were favorable to 2016 in Malaysia as higher average oil and natural gas prices realized, were mostly offset by lower natural gas volume sold, higher lease operating expense, higher depreciation expense, higher administrative expense and higher income tax expense. Crude oil and natural gas sales volumes in Malaysia were lower in the 2017 quarter versus 2016, primarily due to a maintenance shutdown in Sarawak in 2017. Depreciation expense was higher in 2017 compared to the 2016 quarter primarily due to higher unit rates in Block K and Sarawak partly offset by lower volumes sold in Block K and Sarawak.20ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)Third quarter 2017 vs. 2016 (Contd.)Other international E&P operations reported a loss from continuing operations of $11.0 million in the third quarter of 2017 compared to a loss of $8.1 million in the 2016 quarter. The results were $2.9 million lower in the 2017 period versus 2016 primarily related to higher exploration expenses and lower income tax benefits on investments in foreign areas, partially offset by lower selling and general expenses resulting from restructuring activity in 2016.Total hydrocarbon production averaged 153,842 barrels of oil equivalent per day in the 2017 third quarter, which represented a 9% decrease from the 169,844 barrels of oil equivalents per day produced in the 2016 quarter. When the Seal asset sold in 2017 is excluded, the Company’s worldwide production decreased 8% in 2017 compared to 2016. Average crude oil and condensate production was 84,230 barrels per day in the third quarter of 2017 compared to 96,476 barrels per day in the third quarter of 2016. Crude oil production in the Eagle Ford Shale area of South Texas in the 2017 quarter was essentially flat to the same quarter in 2016. Crude oil production in the Gulf of Mexico was lower in the 2017 quarter due to well decline and unplanned downtime. Heavy oil production from the Seal area in Western Canada was divested in mid-January 2017. Onshore oil production in Canada improved in the 2017 quarter in the Company’s Kaybob Duvernay and Placid Montney areas acquired in the third quarter of 2016. Oil production offshore Eastern Canada was lower during 2017 primarily due to unplanned downtime at both Hibernia and Terra Nova fields. Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to lower working interest in the Kakap field subsequent to the redetermination of working interest. On a worldwide basis, the Company's crude oil and condensate prices averaged $49.82 per barrel in the third quarter 2017 compared to $44.64 per barrel in the 2016 period, an increase of 12% quarter to quarter. Total production of natural gas liquids (NGL) was 9,128 barrels per day in the 2017 third quarter compared to 9,703 barrels per day in the same 2016 period. The decrease in NGL production was primarily associated with lower natural gas liquids volumes in the U.S, offset by higher volumes in Canada. The average sales price for U.S. NGL was $18.02 per barrel in the 2017 quarter compared to $11.38 per barrel in 2016. Average NGL prices in Malaysia in the third quarter of 2017 and 2016 were $49.66 per barrel and $45.12 per barrel, respectively.Natural gas sales volumes averaged 363 million cubic feet per day in the third quarter 2017 compared to 382 million cubic feet per day in 2016. Natural gas sales volumes increased in North America for the 2017 period due primarily to new volumes in the Kaybob Duvernay and Placid Montney areas of Western Canada acquired in the third quarter of 2016, and growth in the Tupper Montney business, offset in part by lower volumes produced in both offshore Gulf of Mexico and in Eagle Ford Shale. Natural gas production volumes in Malaysia decreased in the 2017 period due to lower demand and planned downtime at Sarawak in the current period. North American natural gas sales prices averaged $1.93 per thousand cubic feet (MCF) in the 2017 quarter, 2% below the $1.96 per MCF average in the same quarter of 2016. The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.60 per MCF, compared to a price of $3.01 per MCF in the 2016 quarter.Nine months 2017 vs. 2016United States E&P operations reported earnings of $11.0 million in the first nine months of 2017 compared to a loss of $158.5 million in the 2016 period, an improvement of $169.5 million in 2017 compared to the 2016 period. Revenue in the U.S. was $176.5 million in the period as oil and natural gas realized sales prices and unrealized gains on crude oil derivative contracts more than offset lower sales volume. Lease operating expenses decreased by $33.9 million primarily due to lower costs in Eagle Ford Shale and Gulf of Mexico mainly related to cost structure improvements coupled with lower variable costs based on volumes produced. Depreciation expense decreased $54.2 million in 2017 compared to 2016 due to lower unit rates in the Gulf of Mexico in the 2017 period and lower U.S. volume sold. Exploration expenses were $6.6 million higher in the 2017 period primarily related to higher undeveloped lease amortization expense compared to the same period of 2016. Income taxes increased by $87.7 million in the 2017 period due to improvements in net income.21ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)Nine months 2017 vs. 2016 (Contd.)Canadian E&P operations reported earnings of $102.6 million in the first nine months of 2017 compared to a loss of $36.9 million in the 2016 period. Results for conventional operations improved by $187.2 million in 2017 due to a gain of $132.4 million on the sale of Seal heavy oil assets in 2017, lower impairment expense of $95.1 million in 2017 and higher average realized sales prices for crude oil and natural gas, partially offset by lower oil volume sold (from the sale of Seal and Syncrude assets in quarter 1 2017 and quarter 2 2016, respectively), higher lease operating expense for conventional operations and non-recurring income tax benefits recognized on the sale of certain Montney midstream assets in 2016.Malaysia E&P operations reported earnings of $173.9 million in the first nine months of 2017 compared to earnings of $135.1 million during the same period in 2016. Results improved $38.8 million in 2017 in Malaysia primarily due to higher revenue of $53.0 million driven by higher commodity prices received and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold (from Block K due to normal field decline). Depreciation expense was $10.1 million lower in 2017 compared to the same period in 2016 primarily due to lower unit rates in Sarawak and lower oil volume sold, partly offset by higher natural gas volume sold in Sarawak and higher unit rates at Block K.Other international E&P operations reported a loss of $10.9 million in the first nine months of 2017 compared to a loss of $39.2 million in the 2016 period. The 2017 period included lower dry hole costs of $10.4 million, with the higher 2016 costs primarily associated with unsuccessful drilling in Block 11-2/11 in Vietnam. The 2017 period also included income tax benefits on investments in foreign areas of $32.9 million. Other exploration expenses were $5.9 million higher in the current year, mostly attributable to costs in Mexico, Australia and Brazil. Other expenses were $8.8 million higher in the 2017 period primarily related to no repeat of a credit from an adjustment of previously recorded exit costs in 2016 in the Republic of Congo.Total worldwide production averaged 161,917 barrels of oil equivalent per day during the nine months ended September 30, 2017, a 9% decrease from 178,319 barrels of oil equivalent produced in the same period in 2016. When Seal and Syncrude are excluded, the Company’s worldwide production decreased by 4%. Crude oil and condensate production in the first nine months of 2017 averaged 89,580 barrels per day compared to 106,279 barrels per day in 2016. Crude oil production decreased at Eagle Ford Shale in 2017 due to production decline associated with significantly less drilling in response to lower prices and phasing of capital expenditures into late 2017. Heavy oil production declined in 2017 in the Seal area of Western Canada primarily due to divestment of the asset in January 2017. Synthetic oil production in Canada also was nil in 2017 due to the Company’s divestiture of Syncrude Canada Ltd. in the second quarter of 2016. Lower oil production in 2017 in Block K Malaysia was primarily attributable to lower working interest in Kakap field subsequent to the redetermination of working interest. For the first nine months of 2017, the Company’s sales price for crude oil and condensate averaged $49.41 per barrel, up from $40.67 per barrel in 2016. Total production of NGLs was 9,140 barrels per day in the 2017 period compared to 9,275 barrels per day in 2016. The sales price for U.S. NGLs averaged $16.33 per barrel in 2017 compared to $10.31 per barrel in 2016. Natural gas sales volumes increased from 377 million cubic feet per day in 2016 to 379 million cubic feet per day in 2017. Natural gas sales volume increased, primarily due to less unplanned downtime in 2017 in Sarawak. North American natural gas volumes were flat as improvement in Canada due to the 2017 volumes from Kaybob Duvernay and Placid Montney fields were offset in part by lower U.S. volume due to natural field decline. The average sales price for North American natural gas in the first nine months of 2017 was $2.08 per MCF, up from $1.58 per MCF realized in 2016. Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.50 per MCF in 2017 compared to $3.25 per MCF in 2016. Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.22ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)Selected operating statistics for the three-month and nine-month periods ended September 30, 2017 and 2016 follow.84,230 96,476 89,580 106,279 33,070 33,307 33,281 36,790 10,240 11,722 11,309 12,791 3,240 1,288 2,729 791 6,225 9,400 8,100 8,483 2,678 201 2,732 6,194 11,508 12,889 12,727 13,288 19,947 25,192 21,233 25,210 92,033 97,542 89,597 104,525 33,070 33,307 33,281 36,790 10,240 11,722 11,309 12,791 3,240 1,288 2,729 791 6,533 9,027 7,812 8,576 2,678 201 2,732 6,194 13,083 12,641 13,350 12,024 25,867 26,879 20,915 24,627 9,128 9,703 9,140 9,275 6,669 6,940 6,812 6,972 910 1,502 967 1,399 510 307 410 162 1,039 954 951 742 9,213 8,770 9,165 9,289 6,669 6,940 6,812 6,972 910 1,502 967 1,399 510 307 410 162 1,124 21 976 756 362,901 381,988 379,182 376,592 29,476 34,900 32,862 36,430 11,232 16,873 11,654 19,012 223,032 204,816 220,121 206,458 90,181 115,535 106,481 103,327 8,980 9,864 8,064 11,365 153,842 169,844 161,917 178,319 161,730 169,977 161,959 176,579 1The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.2Natural gas converted on an energy equivalent basis of 6:12332ITEM 2. MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)The following table contains hydrocarbons sold during the three-month and six-month periods ended June 30, 2020 and 2019.Three Months Ended
June 30,Six Months Ended
June 30,Barrels per day unless otherwise noted 2020 2019 2020 2019 Continuing operations Net crude oil and condensate United States Onshore 27,986 33,145 29,510 29,532 Gulf of Mexico 166,669 58,842 73,836 61,053 Canada Onshore 7,872 5,943 7,353 6,199 Offshore 5,943 6,723 5,559 7,324 Other — 470 156 468 Total net crude oil and condensate - continuing operations 108,470 105,123 116,414 104,576 Net natural gas liquids United States Onshore 5,303 5,977 5,444 5,641 Gulf of Mexico 15,219 3,118 5,944 2,940 Canada Onshore 1,018 1,073 1,209 1,083 Total net natural gas liquids - continuing operations 11,540 10,168 12,597 9,664 Net natural gas – thousands of cubic feet per day United States Onshore 27,697 32,209 29,830 30,752 Gulf of Mexico 168,717 39,029 75,333 29,356 Canada Onshore 259,108 249,367 262,978 252,120 Total net natural gas - continuing operations 355,522 320,605 368,141 312,228 Total net hydrocarbons - continuing operations including NCI 2,3179,264 168,725 190,368 166,278 Noncontrolling interest Net crude oil and condensate – barrels per day (10,653) (10,715) (11,564) (11,669) Net natural gas liquids – barrels per day (443) (458) (501) (506) Net natural gas – thousands of cubic feet per day 2(4,059) (4,507) (4,575) (4,203) Total noncontrolling interest (11,773) (11,924) (12,828) (12,876) Total net hydrocarbons - continuing operations excluding NCI 2,3167,491 156,801 177,540 153,403 Discontinued operations Net crude oil and condensate – barrels per day — 21,121 — 23,676 Net natural gas liquids – barrels per day — 498 — 580 Net natural gas – thousands of cubic feet per day 2— 93,382 — 97,465 Total discontinued operations — 37,183 — 40,500 Total net hydrocarbons sold excluding NCI 2,3167,491 193,984 177,540 193,903 1 Includes net volumes attributable to a noncontrolling interest in MP GOM.2 Natural gas converted on an energy equivalent basis of 6:13 NCI – noncontrolling interest in MP GOM.33ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)ExplorationResults of Operations (contd.)The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and Production (Contd.)six-month periods ended June 30, 2020 and 2019. Comparative periods are conformed to current presentation.48.49 44.59 48.42 40.65 47.82 43.93 47.48 40.53 43.15 36.36 43.64 41.04 51.26 45.87 50.35 40.15 19.50 25.12 14.20 35.59 52.62 47.05 52.07 43.62 51.36 46.24 50.95 43.70 17.89 10.89 16.12 10.06 19.00 13.65 17.84 11.60 22.77 39.23 22.48 41.04 49.66 45.12 49.94 37.50 2.44 2.24 2.53 1.69 2.49 2.35 2.56 1.81 1.84 1.88 1.99 1.58 3.60 3.01 3.50 3.25 0.25 0.23 0.24 0.24 Three Months Ended
June 30,Six Months Ended
June 30,2020 2019 2020 2019 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore 21.42 64.17 34.59 61.41 Gulf of Mexico 124.77 65.79 37.00 62.62 Canada 2Onshore 16.09 51.83 26.09 50.78 Offshore 20.48 69.23 35.28 65.84 Other — 73.05 63.51 70.50 Natural gas liquids – dollars per barrel United States Onshore 8.03 15.98 9.45 16.55 Gulf of Mexico 17.29 15.78 7.85 18.36 Canada 2Onshore 13.78 28.41 15.04 31.81 Natural gas – dollars per thousand cubic feet United States Onshore 1.62 2.50 1.74 2.68 Gulf of Mexico 11.71 2.60 1.87 2.58 Canada 2Onshore 1.49 1.26 1.55 1.71 Discontinued operations Crude oil and condensate – dollars per barrel Malaysia 3Sarawak — 78.25 — 70.32 Block K — 65.79 — 65.56 Natural gas liquids – dollars per barrel Malaysia 3Sarawak — 41.45 — 48.07 Natural gas – dollars per thousand cubic feet Malaysia 3Sarawak — 2.57 — 3.60 Block K — 0.24 — 0.24 1Prices include the effect of noncontrolling interest share for MP GOM.2 U.S. dollar equivalent.2The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.3Prices are net of payments under the terms of the respective production sharing contracts.24ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016195.9 81.9 220.5 498.3 43.5 28.7 40.6 112.8 10.5 0.3 10.8 128.4 45.9 63.7 1.0 239.0 4.3 2.0 4.4 10.7 (0.6) (2.5) (3.1) 0.1 1.5 1.6 1.5 0.2 7.7 9.4 1.0 0.2 (2.5) 9.2 7.9 20.4 0.2 20.6 21.4 0.4 (2.5) 9.2 28.5 16.6 6.9 4.8 5.1 33.4 0.8 0.5 1.2 2.5 (29.6) (2.8) 108.3 (15.3) 60.6 (9.7) 0.4 40.6 (4.3) 27.0
overhead and interest)(19.9) (3.2) 67.7 (11.0) 33.6 201.8 80.9 202.7 0.2 485.6 59.6 30.7 29.4 119.7 8.5 1.1 9.6 141.1 46.5 62.0 1.5 251.1 4.2 2.8 4.0 11.0 0.8 0.4 (0.2) 1.0 (0.1) 0.1 0.5 0.5 2.5 5.5 8.0 3.2 0.5 5.8 9.5 9.3 1.1 10.4 12.5 1.1 0.5 5.8 19.9 14.7 5.2 0.2 7.4 27.5 1.0 5.4 0.1 6.5 (39.8) (6.5) 101.2 (14.6) 40.3 (12.7) (1.7) 36.2 (6.5) 15.3
overhead and interest)(27.1) (4.8) 65.0 (8.1) 25.0 25ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016696.7 388.1 594.4 1,679.2 135.7 76.8 133.6 346.1 31.6 1.2 32.8 402.3 136.6 160.0 2.9 701.8 12.8 5.9 12.9 31.6 (1.9) 0.8 (1.1) 1.0 0.1 6.0 7.1 5.5 0.3 24.8 30.6 4.6 0.4 0.8 30.8 36.6 39.4 1.4 40.8 44.0 1.8 0.8 30.8 77.4 48.7 21.2 10.5 15.0 95.4 1.5 0.4 9.1 11.0 20.1 144.2 267.5 (48.7) 383.1 9.1 41.6 93.6 (37.8) 106.5
overhead and interest)11.0 102.6 173.9 (10.9) 276.6 520.2 200.2 64.2 541.4 0.2 1,326.2 169.6 73.3 69.9 122.5 435.3 30.0 3.2 2.5 35.7 456.5 137.5 16.5 170.0 4.6 785.1 12.8 8.2 2.4 12.1 35.5 95.1 95.1 0.4 4.5 10.4 15.3 0.6 2.9 0.6 4.8 8.9 4.5 0.5 18.9 23.9 5.5 3.4 5.1 34.1 48.1 31.9 3.4 0.5 35.8 37.4 6.8 5.1 34.6 83.9 49.9 20.9 0.5 8.6 26.6 106.5 1.1 6.3 (8.8) (1.4) (237.1) (144.8) (27.6) 216.8 (56.8) (249.5) (78.6) (60.2) (75.3) 81.7 (17.6) (150.0)
overhead and interest)(158.5) (84.6) 47.7 135.1 (39.2) (99.5) *The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016.26ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net cost of $99.9 million in the 2017 third quarter compared to $39.6 million in the same 2016 quarter. The $60.3 million increased cost in the 2017 period is primarily due to after-tax foreign currency exchange losses of $43.9 million in the 2017 period versus gains in the 2016 period, higher net interest expense of $9.5 million in 2017 and deferred tax charges on undistributed earnings of certain foreign subsidiaries of $4.7 million in 2017, partially offsetCash Provided by lower administrative costs in the current quarter. Net interest costs increased in the 2017 period primarily due to accelerated interest payment upon the early repayment of the December 2017 notes, additional interest on $550 million notes issued in August 2017 (2025 maturity) and an increase of 1.00% on the coupon rates on $950 million of the Company’s outstanding notes effective September 1, 2016 following a downgrade by Moody’s Investor Services in February 2016. Selling and general expenses decreased $4.7 million in the third quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of the cost structure.During the first nine months of 2017, Corporate activities had a net cost of $302.8 million compared to $111.7 million for the same period of 2016. The $191.1 million increased cost in the 2017 period compared to the 2016 period was primarily due to after-tax losses from foreign currency exchange of $86.6 million in the 2017 period versus gains in the 2016 period, deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries of $65.2 million and higher net interest expense of $34.5 million in 2017 due to additional interest on the $550 million notes issued in August 2017 and an increase of 1.00% on the coupon rates on $950 million of the Company’s notes. These were partially offset by lower administrative costs in 2017. During the first nine months of 2017, the Company’s determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the first nine month of 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ nine-month 2017 earnings. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise.Discontinued OperationsThe Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. The after-tax results of these operations for the three-month and nine-month periods ended September 30, 2017 and 2016 are reflected in the following table.(0.7) (0.7) 1.1 (1.0) 1.9 (1.1) (0.6) 0.3 0.4 (1.6) 1.2 (0.8) Financial Condition$819.6$369.4 million for the first ninesix months of 20172020 compared to $280.3$655.4 million during the same period in 2016.2019. The improvement indecreased cash provided by continuing operationsfrom operating activities in 2017 wasis primarily attributable to higher realizedlower sales prices for the Company’s oil($423.5 million) and gas production, lowerhigher lease operating expenses ($85.0 million), partially offset by higher cash payments received on forward swap commodity contracts ($143.9 million), lower general and administrative expenses and rig cancellation payments($45.0 million). See above for explanation of underlying business reasons.Cash Used in 2016 which are discussed below, partially offset by lower volume sold in the current year and higher interest costs. Changes in operating working capital from continuing operations increased cash by $1.1 million during the first nine months of 2017, compared to a use of cash of $152.6 million in 2016. The use of cash in 2016 included $266.6 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015. Proceeds from sales of property and equipment generated cash of $69.1 million in 2017 primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain areas of Eagle Ford Shale in South Texas, while the 2016 period generated cash of $1,154.6 million mainly related to the sale of Syncrude Canada Limited and certain midstream assets in the Tupper area of Western Canada. Other significant sources of cash included $320.8 million in the 2017 period and $712.9 million in 2016 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.Investing Activities27ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Financial Condition (Contd.)$706.4$589.2 million and $781.7$645.2 million in the nine-month periodsix-month periods ended SeptemberJune 30, 20172020 and 2016,2019, respectively. Total cash dividendsIn 2020, this includes $51.6 million used to shareholders amountedfund the development of the King’s Quay FPS which is expected to $129.4 millionbe refunded on the closing of a transaction to sell this asset to a third party. Lower property additions are a result of reducing the capital spending budget in response to the current commodity price environment.34As a result of the lower commodity prices, the Company has made significant reductions to its planned 2020 capital spending for the nine-months ended September 30, 2017 compared to $163.6 million in the same periodremainder of 2016 as the Company lowered the dividend from $1.40 per share to $1.00 per share effective in the third quarter 2016. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $651.2 million in the 2016 period. The proceeds of the $550 million notes issued in August 2017, were used to redeem the Company’s $550 million 2.50% notes in September 2017. The 2.50% notes had a maturity date of December 2017 and were retired early. The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 using proceeds from the sale of assets.Total accrual basis capital expenditures were as follows:Six Months Ended
June 30,(Millions of dollars) 2020 2019 Capital Expenditures 694.7 614.6 Exploration and production $ 550.2 1,966.9 6.9 20.7 Corporate 7.4 5.6 701.6 635.3 Total capital expenditures $ 557.6 1,972.5 The increase in capital expenditures in the exploration and production business in 2017 compared to 2016 was primarily attributable to higher developmental drilling activities in Eagle Ford Shale and Kaybob Duvernay and Placid Montney assets, partially offset by 2016 acquisition costs in the Kaybob Duvernay and liquids rich Placid Montney properties in Canada and lower spending in Malaysia. A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.Six Months Ended
June 30,(Millions of dollars) 2020 2019 706.4 781.7 Property additions and dry hole costs per cash flow statements $ 537.6 645.2 Property additions King's Quay per cash flow statements Property additions King's Quay per cash flow statements 51.6 — Acquisition of oil and gas properties Acquisition of oil and gas properties — 1,226.3 37.7 32.8 Geophysical and other exploration expenses 23.0 32.0 (42.5) (179.2) Capital expenditure accrual changes and other (54.6) 69.0 701.6 635.3 Total capital expenditures $ 557.6 1,972.5 Capital expenditures in the exploration and production business in 2020 compared to 2019 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, with significant capital expenditure reductions in the Eagle Ford Shale. The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party.Cash Provided by Financing ActivitiesNet cash provided by financing activities was $60.0 million for the first six months of 2020 compared to net cash provided by financing activities of $1,113.5 million during the same period in 2019. In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured RCF ($170.0 million). Total cash dividends to shareholders amounted to $57.6 million for the six months ended June 30, 2020 compared to $85.5 million in the same period of 2019 due to shares repurchased throughout 2019 and a 50% reduction in the quarterly dividend effective in the second quarter 2020. As of June 30, 2020 and in the event it is required to fund investing activities from borrowings, the Company has $1,426.3 million available on its committed RCF.In 2019, net cash provided by financing activities was $1.1 billion principally from net borrowings on the RCF ($1,075.0 million) and a short-term loan ($500.0 million) to fund the LLOG acquisition. These borrowings were repaid in July 2019 following the completion of the Malaysia divestment for net sales proceeds of $2.0 billion. In 2019 the Company used cash to buy back issued ordinary shares of $299.9 million.Working CapitalWorking capital (total current assets less total current liabilities)liabilities – excluding assets and liabilities held for sale) at SeptemberJune 30, 20172020 was $615.6$(18.0) million, $558.8$61.1 million morehigher than December 31, 2016,2019, with the increase primarily attributable to the Company redeeming the $550 million in 2.50% notes in September 2017, highera lower cash balancesbalance ($161.3 million), lower accounts payable ($235.9 million), lower accounts receivable ($54.1 million), and lower other accrued liabilities ($45.6 million). Lower accounts payable.35Capital EmployedAt SeptemberJune 30, 2017,2020, long-term debt of $2,908.3$2,956.4 million had increased by $485.5$153.0 million compared to December 31, 2016. 2019, as a result of net borrowing on the RCF. The fixed-rate notes had a weighted average maturity of 7.3 years and a weighted average coupon of 5.9 percent.A summary of capital employed at SeptemberJune 30, 20172020 and December 31, 20162019 follows.June 30, 2020 December 31, 2019 (Millions of dollars) Amount % Amount % Capital employed 2,908.3 36.9 2,422.8 33.0 Long-term debt $ 2,956.4 39.3 % $ 2,803.4 33.9 % 4,980.1 63.1 4,916.7 67.0 Murphy shareholders' equity Murphy shareholders' equity 4,568.5 60.7 % 5,467.5 66.1 % 7,888.4 100.0 7,339.5 100.0 Total capital employed $ 7,525.0 100.0 % $ 8,270.8 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. At SeptemberJune 30, 2017,2020, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5$20.5 million in Canada and $261.6 million in Malaysia.Canada. In addition, $17.0$19.1 million of cash was held in the United Kingdom butand $11.8 million was reflectedheld in Brunei (both of which were reported in current Assets Heldheld for Salesale on the Company’s Consolidated Balance Sheet at SeptemberJune 30, 2017.2020). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to incentivize oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada currently collects a 5% withholding tax onFinancial Condition (Contd.)cashearnings repatriated to the United States through a dividend toU.S.Accounting changes and recent accounting pronouncements – see Note BOutlookAs discussed in the U.S. parent. See the “Corporate”Summary section on page 31 of this Form 10-Q report regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.Accounting and Other MattersBusiness CombinationsIn January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.Compensation – Stock CompensationIn 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 were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Compensation – Retirement BenefitsIn March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Revenue from Contracts with CustomersIn 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 modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures 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 these ASU’s 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 as necessary.Accounting and Other Matters (Contd.)LeasesIn 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 Generally Accepted Accounting Principles (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 the first quarter of 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.Statement of Cash FlowsIn August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides 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.OutlookAverage worldwide24, average crude oil prices in October 2017 have slightly improved fromwere lower during the second quarter of 2020 compared to the average prices during the first quarter of 2020. NYMEX WTI forward curve prices for the balance of 2020 have recovered to an average of $42.07 per barrel at the end of July 2020, however we cannot predict what impact the ongoing COVID-19 pandemic and other economic factors may have on commodity pricing. Lower prices are expected to result in lower profits and operating cash-flows. For the third quarter, production is expected to average between 153 and 163 MBOEPD, excluding NCI. If price volatility persists, the Company will review the option of 2017. North American natural gasproduction curtailments to avoid incurring losses on certain produced barrels.In response to the COVID-19 pandemic and reduced commodity prices, decreased slightly in Octoberthe Company reduced 2020 capital expenditures significantly from the 2017 third quarter.original plan of $1.4 billion to $1.5 billion to a range of $680 million to $720 million, excluding NCI. The Company expects its total oilhas also embarked on a cost reduction plan for both future direct operational expenditures and natural gas production to average 170,000 – 172,000 barrels of oil equivalent per day in the fourth quarter 2017. The Company currently anticipates total capital expenditures for the full year 2017 to be approximately $940 million.20172020 using operating cash flow but will supplement funding where necessary usingwith borrowings under the available revolving credit facilities. If oil and/or natural gasfacility. The Company is closely monitoring the impact of lower commodity prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required duringon its financial position and is currently in compliance with the remainder of yearcovenants related to maintain funding of the revolving credit facility (see Note F). The Company’s ongoing development projects. As of November 1, 2017,August 5, 2020, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:Commodity Type Volumes
(Bbl/d)Price
(USD/Bbl)Remaining Period Area Start Date End Date United States WTI ¹ Fixed price derivative swap 45,000 $56.42 7/1/2020 12/31/2020 United States WTI ¹ Fixed price derivative swap 15,000 $42.93 1/1/2021 12/31/2021 Contract orAverage
(MMcf/d)Price
(CAD/Mcf)Remaining Period CommoditiesLocationDatesVolumes per DayAverage PricesStart Date End Date U.S. OilWest Texas IntermediateOct. – Dec. 201759 22,000 bbls/d$50.41 per bbl.7/1/2020 12/31/2020 U.S. OilWest Texas IntermediateJan. – Dec. 20187,000 bbls/d$51.92 per bbl.TCPL–NOVA SystemJul. – Dec. 2017124 mmcf/dC$2.97 per mcfNatural GasTCPL–NOVA SystemJan. – Dec. 201859 mmcf/dC$2.81 per mcfNatural GasAlberta AllianceNov. 2017 – Mar. 201820 mmcf/dUS$3.51 per mcf**Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate.2836Forward-Looking StatementsThis Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actualone or more of these future events or results not to differ materially from those expressed oroccur as implied in ourby any forward-looking statementsstatement include, but are not limited to,to: macro conditions in the volatility and level of crude oil and natural gas prices,industry, including supply/demand levels, actions taken by major oil exporters and the level andresulting impacts on commodity prices; increased volatility or deterioration in the success rate of Murphy’sour exploration programs the Company’sor in our ability to maintain production rates and replace reserves,reserves; reduced customer demand for Murphy’sour products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements,movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards.in general. For further discussion of risk factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 20162019 Annual Report on Form 10-K on file with the U.S. Securities and3639 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.37ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKThe Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note JL to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.There were commodity transactions in place at SeptemberJune 30, 20172020, covering certain future U.S. crude oil sales volumes in 2017.2020. A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net receivable associated with these derivative contracts by approximately $21.9$35.7 million, while a 10% decrease would have increased the recorded net receivable by a similar amount.There were no derivative foreign exchange contracts in place at SeptemberJune 30, 2017.2020.Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.During the quarter ended SeptemberJune 30, 2017,2020, there were no other changes in the Company'sCompany’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company'sCompany’s internal control over financial reporting.38Murphy isand its subsidiaries are engaged in a number of 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 noteitem is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 20162019 Form 10-K filed on February 24, 2017.27, 2020. The Company has not identified any additional risk factors not previously disclosed in its 20162019 Form 10-K report.report, except as discussed below.Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil, natural gas liquids and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:•worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;•the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;•the production levels of non-OPEC countries, including production levels in the shale plays in the United States;•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;•political instability or armed conflict in oil and natural gas producing regions;•changes in weather patterns and climate;•natural disasters such as hurricanes and tornadoes;•the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;•the effect of conservation efforts;•the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;•technological advances affecting energy consumption and energy supply;•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and•general economic conditions worldwide.In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day in May and June 2020.Further, the recent global downturn, largely triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.For the three months ended June 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $28 (compared to $46 in the first three months of 2020). The closing price for WTI at the end of the second quarter of 2020 was approximately $38 per barrel (compared to $30 at the end of the first quarter), reflecting a 36% reduction from the price at the end of 2019. In comparison, WTI averaged approximately $57 in 2019, $65 in 2018 and $51 in 2017. The closing price for WTI at the end of 2019 was approximately $60 per barrel. As of August 4, 2020 closing, the NYMEX WTI forward curve price for September through December 2020 was $42.07. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the WTI prices.The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended June 30, 2020 was $1.65 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of June 30, 2020, was $1.57 per MMBTU. In comparison, NYMEX was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017 The39closing price for NYMEX natural gas as of December 31, 2019, was $2.19 per MMBTU. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged $1.33 per MMBTU in 2019. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 41 and certain variable netback contracts providing exposure to Malin and Chicago City Gate prices.Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue during 2020 and beyond. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales. See Note L - Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In the first half of 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See “Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company has initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) its joint venture partners and (iii) other counterparties.Murphy is exposed to credit risk in three principle areas:•Accounts receivable credit risk from selling its produced commodity to customers;•Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and•Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices40To mitigate these risks the Company:•Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;•Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.The Exhibit Index on page 3843 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.41SIGNATUREPursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.MURPHYOILCORPORATION (Registrant) By/s/ CHRISTOPHER D. HULSE Christopher D. Hulse Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer) November 1, 2017(Date)August 6, 2020EXHIB(Date)42EXHIBIT INDEXExhibit
No.Exhibit No. Exhibits other than those listed above have been omitted since they are either not required or not applicable.2943