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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 $ 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. 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 – $ $ and Discontinued Operations 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. Note 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 nine-month period ended September 30, 2021. 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 nine-month periods ended September 30, 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% the noncontrolling interest in MP GOM. a reported pre-tax net loss. 2018. Following the divestment of Malaysia in the third quarter of 2019, 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. Operations. Foreign Currency Exchange Risks 2021 and 2020. 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) – $ Fair Values – Recurring 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 $ 2021. 2021. See Note L for additional information. Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings. 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 $ 26. For the three months ended September 30, deferral of asset retirement obligations and after-tax losses on contingent consideration of $22.4 million. project costs from inception to closing with proceeds of $267.7 million. 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 $ 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 $ The Company has presented its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations in its consolidated financial statements. 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 $ 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 $ receivable ($75.3 million). Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS. Lower accounts receivable are principally due to the timing of cash received from our joint venture partners to fund joint operations. September 30, 2017 December 31, 2016 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ % $ % Stockholders' equity % % Total capital employed $ % $ % any affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its remaining capital program in 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 atOctober 31, 2017 2021was 172,572,873.154,459,128.MURPHYMURPHY OIL CORPORATIONTABLE OF CONTENTS2336361CONSOLIDATED 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) September 30,
2021December 31,
2020ASSETS Current assets Cash and cash equivalents $ 505,067 310,606 Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020 186,683 262,014 Inventories 57,411 66,076 Prepaid expenses 40,583 33,860 Assets held for sale 40,987 327,736 Total current assets 830,731 1,000,292 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020 8,112,093 8,269,038 Operating lease assets 918,719 927,658 Deferred income taxes 442,212 395,253 Deferred charges and other assets 27,101 28,611 Total assets $ 10,330,856 10,620,852 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 646 — Accounts payable 615,436 407,097 Income taxes payable 18,035 18,018 Other taxes payable 26,997 22,498 Operating lease liabilities 157,294 103,758 Other accrued liabilities 316,205 150,578 Liabilities associated with assets held for sale — 14,372 Total current liabilities 1,134,613 716,321 Long-term debt, including finance lease obligation 2,613,703 2,988,067 Asset retirement obligations 797,627 816,308 Deferred credits and other liabilities 723,732 680,580 Non-current operating lease liabilities 781,114 845,088 Deferred income taxes 166,120 180,341 Total liabilities 6,216,909 6,226,705 Equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued — — Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2021 and 195,100,628 shares in 2020 195,101 195,101 Capital in excess of par value 921,227 941,692 Retained earnings 5,069,578 5,369,538 Accumulated other comprehensive loss (580,174) (601,333) Treasury stock (1,656,224) (1,690,661) Murphy Shareholders' Equity 3,949,508 4,214,337 Noncontrolling interest 164,439 179,810 Total equity 4,113,947 4,394,147 Total liabilities and equity $ 10,330,856 10,620,852 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
September 30,Nine Months Ended
September 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) 2021 2020 2021 2020 Revenues and other income Revenues and other income Revenue from sales to customers Revenue from sales to customers $ 687,549 425,324 $ 2,038,905 1,311,627 (Loss) gain on derivative instruments (Loss) gain on derivative instruments (59,164) (5,290) (499,794) 319,502 Gain on sale of assets and other income Gain on sale of assets and other income 2,315 1,831 21,217 6,006 Total revenues and other income Total revenues and other income 630,700 421,865 1,560,328 1,637,135 Costs and expenses 112,751 119,663 346,072 435,296 Lease operating expenses 130,131 124,491 403,708 478,283 10,816 9,592 32,771 35,668 Severance and ad valorem taxes 11,670 6,781 32,215 22,645 28,492 19,866 77,356 83,910 Transportation, gathering and processing Transportation, gathering and processing 44,588 41,322 137,196 126,779 Exploration expenses, including undeveloped lease amortization Exploration expenses, including undeveloped lease amortization 24,517 12,092 49,840 61,686 56,672 55,523 168,259 196,143 Selling and general expenses 27,210 28,509 85,826 104,381 Restructuring expenses Restructuring expenses — 4,982 — 46,379 243,636 255,900 714,782 797,288 Depreciation, depletion and amortization 189,806 231,603 615,372 769,151 10,654 11,043 31,638 35,514 Accretion of asset retirement obligations 12,198 10,778 34,854 31,213 95,088 Impairment of assets — 219,138 171,296 1,206,284 2,454 6,486 10,988 (1,446) Other (benefit) expense Other (benefit) expense (32,791) 20,224 58,616 (2,957) 465,475 478,073 1,381,866 1,677,461 Total costs and expenses 407,329 699,920 1,588,923 2,843,844 32,844 7,473 301,372 (347,773) Operating income (loss) from continuing operations 223,371 (278,055) (28,595) (1,206,709) Other income (loss) (47,721) 14,987 (93,524) 38,602 Interest income and other (loss) Interest income and other (loss) (1,593) (5,177) (11,459) (10,107) (48,681) (39,219) (138,423) (103,889) Interest expense, net (46,925) (45,182) (178,399) (124,877) (96,402) (24,232) (231,947) (65,287) Total other loss (48,518) (50,359) (189,858) (134,984) (63,558) (16,759) 69,425 (413,060) Income (loss) from continuing operations before income taxes 174,853 (328,414) (218,453) (1,341,693) 2,760 (2,176) 95,602 (201,897) Income tax expense (benefit) 36,838 (62,584) (62,498) (248,890) (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) Income (loss) from continuing operations Income (loss) from continuing operations 138,015 (265,830) (155,955) (1,092,803) (Loss) from discontinued operations, net of income taxes (Loss) from discontinued operations, net of income taxes (706) (778) (600) (6,907) Net income (loss) including noncontrolling interest Net income (loss) including noncontrolling interest 137,309 (266,608) (156,555) (1,099,710) Less: Net income (loss) attributable to noncontrolling interest Less: Net income (loss) attributable to noncontrolling interest 28,853 (23,055) 85,509 (122,869) NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 108,456 (243,553) $ (242,064) (976,841) INCOME (LOSS) PER COMMON SHARE – BASIC (0.38) (0.08) (0.15) (1.23) Continuing operations $ 0.70 (1.58) $ (1.57) (6.31) (0.01) 0.01 (0.01) Discontinued operations — (0.01) — (0.05) (0.38) (0.09) (0.14) (1.24) Net income (loss) Net income (loss) $ 0.70 (1.59) $ (1.57) (6.36) INCOME (LOSS) PER COMMON SHARE – DILUTED (0.38) (0.08) (0.15) (1.23) Continuing operations $ 0.70 (1.58) $ (1.57) (6.31) (0.01) 0.01 (0.01) Discontinued operations — (0.01) — (0.05) (0.38) (0.09) (0.14) (1.24) Net income (loss) Net income (loss) $ 0.70 (1.59) $ (1.57) (6.36) 0.25 0.25 0.75 0.95 Cash dividends per Common share $ 0.125 0.125 0.375 0.500 Average Common shares outstanding (thousands) 172,573 172,199 172,509 172,165 Basic 154,439 153,596 154,239 153,480 172,573 172,199 172,509 172,165 Diluted 155,932 153,596 154,239 153,480 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
September 30,Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 2021 2020 Net income (loss) including noncontrolling interest $ 137,309 (266,608) $ (156,555) (1,099,710) Other comprehensive (loss) income, net of tax Net (loss) gain from foreign currency translation (31,308) 28,323 6,534 (39,520) Retirement and postretirement benefit plans 4,653 3,726 12,935 (45,219) Deferred loss on interest rate hedges reclassified to interest expense — 297 1,690 905 Other comprehensive (loss) income (26,655) 32,346 21,159 (83,834) COMPREHENSIVE INCOME (LOSS) $ 110,654 (234,262) $ (135,396) (1,183,544) See Notes to Consolidated Financial Statements, page 7.7.4CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)(ThousandsNine Months Ended
September 30,(Thousands of dollars) 2021 2020 Operating Activities Net income (loss) including noncontrolling interest $ (156,555) (1,099,710) Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities Loss from discontinued operations 600 6,907 Depreciation, depletion and amortization 615,372 769,151 Dry hole and previously suspended exploration costs 17,899 8,255 Amortization of undeveloped leases 13,872 21,951 Accretion of asset retirement obligations 34,854 31,213 Impairment of assets 171,296 1,206,284 Noncash restructuring expense — 17,565 Deferred income tax (benefit) expense (65,149) (231,748) Mark to market loss (gain) on contingent consideration 105,111 (29,476) Mark to market loss (gain) on derivative instruments 228,497 (104,463) Long-term non-cash compensation 42,080 35,200 Net decrease (increase) in noncash working capital 117,330 (26,261) Other operating activities, net (33,924) (26,837) Net cash provided by continuing operations activities 1,091,283 578,031 Investing Activities Property additions and dry hole costs (564,230) (648,725) Property additions for King's Quay FPS (17,734) (74,936) Proceeds from sales of property, plant and equipment 270,038 — Net cash required by investing activities (311,926) (723,661) Financing Activities Borrowings on revolving credit facility 165,000 450,000 Repayment of revolving credit facility (365,000) (250,000) Retirement of debt (726,358) (12,225) Debt issuance, net of cost 541,913 (613) Early redemption of debt cost (36,756) — Distributions to noncontrolling interest (100,880) (43,673) Cash dividends paid (57,896) (76,790) Withholding tax on stock-based incentive awards (4,973) (7,094) Capital lease obligation payments (643) (514) Net cash (required) provided by financing activities (585,593) 59,091 Cash Flows from Discontinued Operations 1Operating activities — (1,202) Investing activities — 4,494 Financing activities — — Net cash provided by discontinued operations — 3,292 Effect of exchange rate changes on cash and cash equivalents 697 (585) Net increase (decrease) in cash and cash equivalents 194,461 (87,124) Cash and cash equivalents at beginning of period 310,606 306,760 Cash and cash equivalents at end of period $ 505,067 219,636 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
September 30,Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 2021 2020 Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued $ — — $ — — Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2021 and 195,100,628 shares at September 30, 2020 Balance at beginning of period 195,101 195,101 195,101 195,089 Exercise of stock options — — — 12 Balance at end of period 195,101 195,101 195,101 195,101 Capital in Excess of Par Value Balance at beginning of period 915,181 931,429 941,692 949,445 Exercise of stock options, including income tax benefits (35) — (661) (156) Restricted stock transactions and other (402) (409) (38,749) (33,649) Share-based compensation 6,483 5,298 18,945 20,678 Balance at end of period 921,227 936,318 921,227 936,318 Retained Earnings Balance at beginning of period 4,980,428 5,823,426 5,369,538 6,614,304 Net (loss) attributable to Murphy 108,456 (243,553) (242,064) (976,841) Cash dividends (19,306) (19,200) (57,896) (76,790) Balance at end of period 5,069,578 5,560,673 5,069,578 5,560,673 Accumulated Other Comprehensive Loss Balance at beginning of period (553,519) (690,341) (601,333) (574,161) Foreign currency translation gain (loss), net of income taxes (31,308) 28,323 6,534 (39,520) Retirement and postretirement benefit plans, net of income taxes 4,653 3,726 12,935 (45,219) Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes — 297 1,690 905 Balance at end of period (580,174) (657,995) (580,174) (657,995) Treasury Stock Balance at beginning of period (1,656,591) (1,691,070) (1,690,661) (1,717,217) Awarded restricted stock, net of forfeitures 343 409 33,888 26,556 Exercise of stock options 24 — 549 — Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost (1,656,224) (1,690,661) (1,656,224) (1,690,661) Murphy Shareholders’ Equity 3,949,508 4,343,436 3,949,508 4,343,436 Noncontrolling Interest Balance at beginning of period 161,228 204,937 179,810 337,151 Net income (loss) attributable to noncontrolling interest 28,853 (23,055) 85,509 (122,869) Distributions to noncontrolling interest owners (25,642) (11,273) (100,880) (43,673) Balance at end of period 164,439 170,609 164,439 170,609 Total Equity $ 4,113,947 4,514,045 $ 4,113,947 4,514,045 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 natural gas exploration and production 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 Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) acquisition, 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 September 30, 2021, our maximum exposure to loss was $3.4 million (excluding operational impacts), 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 September 30, 20172021 and December 31, 2016,2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 20172021 and 2016,2020, 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.FinancialConsolidated 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 2020 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-month periods ended September 30, 20172021 are not necessarily indicative of future results.BeginningNote B – New Accounting Principles and Recent Accounting PronouncementsAccounting Principles AdoptedIncome Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting 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. The Company adopted this guidance in the periodfirst quarter of 2021 and it did not have a material impact on its consolidated financial statements.Recent Accounting PronouncementsNone affecting the Company.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 natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural 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 natural 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 natural 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 natural 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 include long-term floating commodity index priced and 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.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note C – Revenue from Contracts with Customers(Contd.)Disaggregation of RevenueThe Company reviews performance based on 2 key geographical segments and between onshore and offshore sources of revenue within these geographies.For the three-month and nine-month periods ended September 30, 2017, certain reclassifications in presentation have been made to2021, the Consolidated StatementsCompany recognized $687.5 million and $2,038.9 million, respectively, from contracts with customers for the sales of Operations. Theoil, natural gas liquids and natural gas. For the three-month and nine-month periods ended September 30, 2020, the Company now presents a separate “Operating income (loss)recognized $425.3 million and $1,311.6 million, respectively, from continuing operations” subtotalcontracts with customers for the sales of oil, natural gas liquids and natural gas.Three Months Ended
September 30,Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 2021 2020 Net crude oil and condensate revenue United States Onshore $ 167,010 86,498 464,767 272,284 Offshore 340,001 216,918 1,079,418 714,143 Canada Onshore 29,110 32,358 89,708 67,268 Offshore 20,499 19,173 70,333 54,864 Other — — — 1,806 Total crude oil and condensate revenue 556,620 354,947 1,704,226 1,110,365 Net natural gas liquids revenue United States Onshore 16,356 6,766 33,480 16,145 Offshore 11,046 4,765 31,866 13,255 Canada Onshore 4,501 2,780 11,728 6,090 Total natural gas liquids revenue 31,903 14,311 77,074 35,490 Net natural gas revenue United States Onshore 11,127 4,529 24,442 14,177 Offshore 17,444 9,827 56,855 35,487 Canada Onshore 70,455 41,710 176,308 116,108 Total natural gas revenue 99,026 56,066 257,605 165,772 Total revenue from contracts with customers 687,549 425,324 2,038,905 1,311,627 (Loss) gain on derivative instruments (59,164) (5,290) (499,794) 319,502 Gain on sale of assets and other income 2,315 1,831 21,217 6,006 Total revenue and other income $ 630,700 421,865 1,560,328 1,637,135 Contract Balances and Asset RecognitionAs of September 30, 2021, and December 31, 2020, 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 $144.0 million and $135.2 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, 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 revenue contracts that have financing components as at September 30, 2021.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 natural 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 September 30, 2021, 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:
1 These contracts are scheduled to commence after the balance sheet date, at various dates between Q4 2021 and Q1 2022.Current Long-Term Contracts Outstanding at September 30, 2021 Location Commodity End Date Description Approximate Volumes 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 2021 Contracts to sell natural gas at USD index pricing 10 MMCFD Canada Natural Gas Q4 2022 Contracts to sell natural gas at USD index pricing 8 MMCFD Canada Natural Gas Q4 2022 Contracts to sell natural gas at CAD fixed prices 5 MMCFD Canada Natural Gas Q4 2022 Contracts to sell natural gas at USD fixed pricing 20 MMCFD Canada Natural Gas Q4 2023 1 Contracts to sell natural gas at USD index pricing 25 MMCFD Canada Natural Gas Q4 2023 Contracts to sell natural gas at CAD fixed prices 38 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD index pricing 31 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD fixed prices 100 MMCFD Canada Natural Gas Q4 2024 1 Contracts to sell natural gas at CAD fixed prices 34 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD fixed pricing 15 MMCFD Canada Natural Gas Q4 2026 1 Contracts to sell natural gas at USD index pricing 49 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.AtAs of September 30, 2017,2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4$186.6 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 20172021 and 2016.2020.148,500 130,514 51,614 847 (13,370) (8,360) (3,205) 178,384 128,156 10NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note D – Property, Plant and Equipment (Contd.)(Thousands of dollars) 2021 2020 Beginning balance at January 1 $ 181,616 217,326 Additions pending the determination of proved reserves 5,007 9,941 Capitalized exploratory well costs charged to expense — (39,408) Balance at September 30 $ 186,623 187,859 The capitalized well costs charged to expense during the first nine months of 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to commodity prices.2020 represent a charge for asset impairments (see below).6NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note B – Property, Plant and Equipment (Contd.)September 30, 2021 2020 (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 $ 3,297 2 2 8,000 1 — 8,430 2 2 53,101 3 3 One to two years — — — 54,334 5 5 43,197 1 1 31,627 2 Two to three years 53,078 5 5 — — — 85,148 7 1 32,865 4 Three years or more 130,248 6 — 125,525 6 — 178,384 13 6 128,156 11 5 $ 186,623 13 7 187,859 12 5 Of the $136.8$183.3 million of exploratory well costs capitalized more than one year at September 30, 2017, $70.42021, $92.3 million is in Vietnam, $45.0 million is in the U.S., $25.9 million is in Brunei, $43.2$15.3 million is in VietnamMexico, and $23.2$4.8 million is in Malaysia.Canada. 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 inImpairmentsDuring the first quarter of 2017 related2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due 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 associatedstatus, including agreements with the Syncrude divestiture.During the second quarter 2016, a Canadian subsidiarypartners, of the Company completed a divestiture of natural gas processingoperating and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. A gain on sale of approximately $187.0 million was deferred and is being recognized over the next 19 years in the Canadian operating segment. The Company amortized approximately $5.3 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 quarter 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of September 30, 2017, $32.0 million of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.7NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note B – Property, Plant and Equipment (Contd.)ImpairmentsDeclinesIn 2020, declines in future oil and natural gas prices in early 2016(principally driven by reduced demand from the COVID-19 pandemic) 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$1,206.3 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 Note J.OtherThe Company has an interest infollowing table reflects the Kakap field in Block K Malaysia. The Kakap field is operated by another companyrecognized impairments for the nine months ended September 30, 2021 and 2020.Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 U.S. $ — 1,152,515 Canada 171,296 — Other Foreign — 39,709 Corporate — 14,060 $ 171,296 1,206,284 DivestmentsDuring the first quarter of 2021, the King’s Quay FPS 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,sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses 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 millionfor previously incurred capital expenditures.11Note CE – Discontinued Operations and Assets Held for SaleThe Company has accounted for its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 20172021 and 20162020 were as follows:598 5 853 1,454 425 (1,593) 1,177 (885) 425 (1,593) 1,177 (885) Three Months Ended
September 30,Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 2021 2020 Revenues $ 144 — $ 801 4,074 Costs and expenses Other costs and expenses (benefits) 850 778 1,401 10,981 (Loss) income before taxes (706) (778) (600) (6,907) Income tax expense — — — — (Loss) income from discontinued operations $ (706) (778) $ (600) (6,907) Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).The following table presentsAs of September 30, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the major categoriesnet property, plant equipment of assetsCA-2 project in Brunei and liabilitiesthe Company’s office building in El Dorado, Arkansas. As of U.K. refining and marketing operations and Seal operationsJune 30, 2021, the CA-1 asset in Canada reflected asBrunei is no longer being marketed for sale.As of December 31, 2020, assets held for sale onincluded the company’s Consolidated Balance Sheets at September 30, 2017King’s Quay Floating Production System (FPS) of $250.1 million (sold in March 2021), the Brunei exploration and December 31, 2016.production properties, and the Company’s office building in El Dorado, Arkansas.(Thousands of dollars) September 30,
2021December 31,
2020Current assets 17,030 4,126 Cash $ — 10,185 6,218 22,944 23,248 27,070 Inventories Inventories — 406 Property, plant, and equipment, net Property, plant, and equipment, net 40,987 307,704 Deferred income taxes and other assets Deferred income taxes and other assets — 9,441 Total current assets associated with assets held for sale Total current assets associated with assets held for sale $ 40,987 327,736 Current liabilities 605 270 Accounts payable $ — 5,306 2,665 2,506 Other accrued liabilities Other accrued liabilities — 45 Current maturities of long-term debt (finance lease) Current maturities of long-term debt (finance lease) — 737 Taxes payable Taxes payable — 1,510 Long-term debt (finance lease) Long-term debt (finance lease) — 6,513 Asset retirement obligation Asset retirement obligation — 261 3,270 2,776 Total current liabilities associated with assets held for sale $ — 14,372 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 DebtAs of September 30, 2021, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At September 30, 2017, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019. At September 30, 2017,2021, the Company had no outstanding borrowings under the 2016 facility, however, there were $84.8RCF and $31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. AdvancesRCF. At September 30, 2021, 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 1.78%. At September 30, 2017,2021, the Company was in compliance with all covenants related to the 2016 facility.In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022; collectively12NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note F – Financing Arrangements and Debt (Contd.)the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.In August 2021, the Company redeemed $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.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 2017,15, 2024.Subsequent to quarter end, the Company sold $550issued a notice of partial redemption with respect to $150.0 million aggregate principal amount of newits 6.875% senior notes that bear interestdue 2024 (2024 Notes). The Company will redeem the 2024 Notes at the rateapplicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to the date of 5.75% and mature on August 15, 2025.redemption. The Company incurred transaction costsredemption date 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 payment2024 Notes 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, 2017.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)EG – 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 Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: Decrease in accounts receivable ¹ $ 75,100 251,706 Decrease in inventories 9,718 4,747 (Increase) in prepaid expenses (6,682) (17,400) Increase (decrease) in accounts payable and accrued liabilities ¹ 40,687 (264,078) (Decrease) in income taxes payable (1,493) (1,236) Net (increase) decrease in noncash operating working capital $ 117,330 (26,261) Supplementary disclosures: Cash income taxes paid, net of refunds $ 1,685 (12,559) Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020 127,793 139,651 Non-cash investing activities: Asset retirement costs capitalized ² $ 36,300 6,342 Decrease in capital expenditure accrual 31,301 74,742 *2016 balance included payments for deepwater rig contract exit1 Excludes receivable/payable balances relating to mark-to-market of $266.6 million.derivative instruments 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.The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 20172021 and 2016.2020.Three Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) (Thousands of dollars) 2021 2020 2021 2020 Service cost Service cost $ 1,770 1,664 328 342 Interest cost Interest cost 4,258 4,827 521 612 Expected return on plan assets Expected return on plan assets (6,038) (5,773) — — Amortization of prior service cost (credit) Amortization of prior service cost (credit) 155 149 — — Recognized actuarial loss Recognized actuarial loss 5,269 5,690 (8) (24) Net periodic benefit expense Net periodic benefit expense $ 5,414 6,557 841 930 Nine Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2021 2020 2021 2020 2,037 2,610 427 674 Service cost $ 5,306 5,996 981 1,235 7,261 5,913 966 1,109 Interest cost 12,844 16,381 1,563 2,200 (8,070) (6,626) Expected return on plan assets (18,326) (18,414) — — 259 323 (18) (21) Amortization of prior service cost (credit) 467 515 — — 2 3,610 3,617 38 Recognized actuarial loss 15,829 14,223 (23) (24) 5,097 5,837 1,375 1,802 Net periodic benefit expense $ 16,120 18,701 2,521 3,411 6,099 8,533 1,276 2,022 20,267 20,386 2,899 3,324 (21,730) (21,709) 767 963 (55) (62) 4 10,673 10,864 113 822 (19) 16,076 19,859 4,120 5,382 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 $ 16,120 27,722 2,521 1,586 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 the U.S. undertaken by the Company in the first quarterConsolidated Statements of 2016.During the nine-month period ended September 30, 2017,2021, the Company made contributions of $24.0$31.0 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 20172021 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8$10.9 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 20122020 Long-Term Incentive Plan (2012(2020 Long-Term 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 and14other stock-based incentives. The 20122020 Long-Term Plan expires in 2022.2030. A total of 8,700,0005000000 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 shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in 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.During the first nine months of 2021, the Committee granted in future years. the following awards from the 2020 Long-Term Plan:2020 Long-Term Incentive PlanType of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Performance Based RSUs 11,156,800 February 2, 2021 $ 16.03 Monte Carlo at Grant Date Time Based RSUs 2385,600 February 2, 2021 $ 12.30 Average Stock Price at Grant Date Cash Settled RSUs 31,022,700 February 2, 2021 $ 12.30 Average Stock Price at Grant Date 1 Performance based RSUs are scheduled to vest over a three year performance period.2 Time based RSUs are generally scheduled to vest over three years from the date of grant.3 Cash settled RSUs are scheduled to vest over three years from the date of grant.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.At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The Company had an Employee Stock Purchase2021 NED Plan (ESPP) that permittedpermits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company shares during 2016currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan. All awards on or after May 12, 2021, will be made under the 2021 NED Plan.During the first sixnine months of 2017. The ESPP terminated on June 30, 2017 and was not renewed by the Company.In February 2017,2021, the Committee granted stock optionsthe following awards to Non-Employee Directors:2018 Stock Plan 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 556,000 performance-basedRSU and 282,000Non-Employee DirectorsType of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Time Based RSUs 1182,652 February 3, 2021 $ 13.14 Closing Stock Price at Grant Date 1 Non-employee directors time-based RSURSUs are scheduled to vest in February 2017.2022.2021 Stock Plan for Non-Employee DirectorsType of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Time Based RSUs 15,655 June 10, 2021 $ 23.58 Closing Stock Price at Grant Date 1 Non-employee directors time-based RSUs are scheduled to vest in February 2022.All stock option exercises are non-cash transactions for the Company. The fair valueemployee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the performance-based RSU, using a Monte Carlo valuation model, ranged from $24.10 to $28.28 per unit. The fair value of time-based RSU was estimated based onshare-based payment arrangements were immaterial for the fair market value of the Company’s stock on the date of grant, which was $28.505 per share. Additionally, the Committee granted 329,400 SAR and 154,150 units of cash-settled RSU (RSUC) to certain employees. The SAR and RSUC 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 SAR was equivalent to the stock options granted, while the initial value of RSUC was equivalent to equity-settled restricted stock units granted. Also in February, the Committee granted 83,220 shares of time-based RSU to the Company’s Directors under the Non-Employee Director Plan. These shares vest on the third anniversary of the date of grant. The estimated fair value of these awards was $28.84 per unit on date of grant.For all periods presented, the Company had no stock options exercised.Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:Nine Months Ended
September 30,(Thousands of dollars) 2021 2020 28,264 35,948 Compensation charged against income before tax benefit Compensation charged against income before tax benefit $ 29,145 17,542 8,695 11,796 Related income tax benefit recognized in income 4,120 2,278 1115Note HJ – Earnings perPer ShareNet loss(loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the20172021 and 2016.2020. The following table reconcilesreports the weighted-average shares outstanding used for these computations.Three Months Ended September 30, Nine Months Ended
September 30,(Weighted-average shares) 2021 2020 2021 2020 172,572,873 172,199,350 172,509,418 172,164,683 Basic method 154,439,313 153,596,109 154,239,440 153,479,654 Dilutive stock options and restricted stock units ¹ Dilutive stock options and restricted stock units ¹ 1,492,949 — — — 172,572,873 172,199,350 172,509,418 172,164,683 Diluted method 155,932,262 153,596,109 154,239,440 153,479,654 *1Due to a net lossesloss recognized by the Company for allthe nine-month period ended September 30, 2021 and the three-month and nine-month periods presented,ended September 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 September 30, Nine Months Ended
September 30,2021 2020 2021 2020 Antidilutive stock options excluded from diluted shares 1,316,222 2,111,068 1,502,758 2,305,973 Weighted average price of these options $ 34.42 $ 38.54 $ 34.97 $ 40.15 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-month periods ended September 30, 20172021 and 2016,2020, the Company’s effective income tax rates were as follows:2021 2020 Three months ended September 30, 21.1% 19.1% Nine months ended September 30, 28.6% 18.6% 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 September 30, 20172021 was belowabove the U.S. statutory tax rate of 35%21% primarily due to income generated in Canada, which has a higher tax rate, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax effect of expenses in foreign jurisdictions not fully deductible from losses atrate on income.The effective tax rate for the U.S.three-month period ended September 30, 2020 was below the statutory tax rate an estimated U.S. tax charge for undistributedof 21% due to exploration expenses in certain foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by the U.S.jurisdictions in which no income tax benefit recognizedis available, as well as no tax benefit available from the reversalpre-tax loss of an uncertain tax position for federal tax years 2011-2013.The effective tax rate for the nine-month period ended September 30, 20172021 was above the U.S. statutory tax rate of 35%21% primarily due to an estimated U.S.no tax charge for undistributed foreign earnings and Canadian foreign exchange losses. These impacts were partially offset byapplied to 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 consequencepre-tax income of the future repatriationnoncontrolling interest in MP GOM, which has the impact of these subsidiaries earnings duringincreasing 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 September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized. on an overall loss.The effective tax rate for the nine-month period ended September 30, 20162020 was abovebelow the U.S. statutory tax rate primarilyof 21% due to deferred tax benefits recognized related to the Canadian asset dispositions andexploration expenses in certain foreign jurisdictions in which no income tax benefitsbenefit 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 investments in foreign areas. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.authorities, and currently the Company is under audit in several of these jurisdictions. 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 September 30, 2017,2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2014;2016; Canada – 2012;2016; Malaysia – 2010;2014; and16United Kingdom – 2015.Note JL – Financial Instruments and Risk ManagementMurphy often uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, 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 previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss untilother comprehensive loss and amortized to the anticipated transactions occur. Thisincome statement over time. During the nine-month period ended September 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred cost is being reclassifiedloss on the interest rate swap of $2.1 million to Interest expense net in the Consolidated StatementsStatement of Operations over the period until the associated notes mature in 2022.Commodity Purchase Price RisksThe Company is subject to commodity price risk related tohas entered into crude oil it producesswaps and sells. Duringcollar contracts. Under the first nine months 2017 and 2016, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production. Under theseswaps contracts, which maturedmature monthly, the Company paidpays the average monthly price in effect and receivedreceives the fixed contract prices. price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also mature monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.At September 30, 2017, the Company had 22,000 barrels2021, volumes per day in WTIassociated with outstanding crude oil swap financial contracts maturing ratably during the remainder of 2017 at an average price of $50.41 and 6,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $51.83. At September 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 increasedand the loss before income taxes by $3.2 millionweighted average prices for the nine-month period ended September 30, 2017.At September 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financialthese contracts maturing ratably during 2016. At September 30, 2016, the fair value of WTI contracts 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, 2016.12September 30, 2021 2021 2022 NYMEX WTI swap contracts: Volume per day (Bbl): 45,000 20,000 Price per Bbl: $ 42.77 $ 44.88 NYMEX WTI collar contracts: Volume per day (Bbl): — 16,000 Price per Bbl: Ceiling: $ — $ 71.83 Floor: — 60.38 NOTES 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 no foreign currency exchange short-term derivatives outstanding at September 30, 2017.At September 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, 20172021 and December 31, 2016,2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.(3,226) (48,864) (73) 17NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note L – Financial Instruments and Risk Management(Contd.)September 30, 2021 December 31, 2020 (Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity swaps Accounts receivable $ — Accounts receivable 13,050 Accounts payable (312,448) Accounts payable (89,842) Deferred credits and other liabilities (41,645) Deferred credits and other liabilities (12,833) Commodity collars Accounts receivable — Accounts receivable — Accounts payable (15,929) Accounts payable — For the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, 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 September 30, Nine months ended September 30, Type of Derivative Contract 2021 2020 2021 2020 (13,573) 11,871 50,365 (22,678) 143 73 26,929 (13,573) 12,014 50,438 4,251 Commodity swaps Commodity swaps (Loss) gain on derivative instruments $ (43,235) (5,290) (483,865) 319,502 Commodity collars Commodity collars (Loss) gain on derivative instruments (15,929) — (15,929) — 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-month periods ended September 30, 2017 and 2016, $2.2 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss deferred on these matured contracts at September 30, 2017 was $8.9 million, which is recorded, net of income taxes of $4.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining three months of 2017.13NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note J – Financial Instruments and Risk Management (Contd.)The 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 September 30, 20172021 and December 31, 20162020, are presented in the following table.
savings plans15,161 15,161 13,904 13,904 3,226 3,226 48,864 48,864
derivative contracts73 73 15,161 3,226 18,387 13,904 48,937 62,841 September 30, 2021 December 31, 2020 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity swaps $ — — — — — 13,050 — 13,050 $ — — — — — 13,050 — 13,050 Liabilities: Commodity collars $ — 15,929 — 15,929 — — — — Nonqualified employee savings plan 17,180 — — 17,180 14,988 — — 14,988 Commodity swaps — 354,093 — 354,093 — 102,675 — 102,675 Contingent consideration — — 238,115 238,115 — — 133,004 133,004 $ 17,180 370,022 238,115 625,317 14,988 102,675 133,004 250,667 The fair value of WTIcommodity (WTI crude oiloil) derivative contracts in 20172021 and 2016 was2020 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. Thebefore tax income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and other operating revenuesGain (loss) on derivative instruments 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.18NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note L – Financial Instruments and Risk Management(Contd.)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 expense (benefit) in the Consolidated Statements of Operations. Contingent consideration is payable annually in years 2022 to 2026.The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 20172021 and December 31, 2016.2020.14NOTES 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, 20162020 and September 30, 20172021 and the changes during the nine-month period ended September 30, 20172021, 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) (Thousands of dollars) Foreign
Currency
Translation
Gains (Losses)Retirement
and
Postretirement
Benefit Plan
AdjustmentsDeferred
Loss on
Interest Rate
Derivative
HedgesTotal Balance at December 31, 2020 $ (324,011) (275,632) (1,690) (601,333) Components of other comprehensive income (loss): Before reclassifications to income and retained earnings 6,534 — — 6,534 Reclassifications to income — 12,935 ¹ 1,690 ² 14,625 Net other comprehensive income (loss) 6,534 12,935 1,690 21,159 Balance at September 30, 2021 $ (317,477) (262,697) — (580,174) 1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017$16,282 are included in the computation of net periodic benefit expense.expense for the nine-month period ended September 30, 2021. See Note GH for additional information. Related income taxes of $3,873$3,347 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2017 are included in Income tax expense.2Reclassifications before taxes of $2,222$2,140 are included in Interest expense, net, for the nine-month period ended September 30, 2017 are included in Interest expense, net.2021. Related income taxes of $777$450 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2017 are included in Income tax expense.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;increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural 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 LENVIRONMENTAL, HEALTH AND SAFETY MATTERS – Environmental and Other Contingencies (Contd.)environment. environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health andsafety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.Violation of federal or state environmental, health and safety 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 environment19NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note N– Environmental and Other Contingencies (Contd.)could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable laws and regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.The Biden administration has indicated that it intends to increase regulatory oversight of the oil and gas industry, with a focus on climate change and greenhouse gas emissions (including methane emissions). The Biden administration has issued a number of executive orders that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. The Biden administration has also issued orders related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021.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, hazardousHazardous 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 investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by priorowners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The CompanyMurphy USA Inc. has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.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 area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified. 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 regulationsadditional expenditures could require additional expendituresbe required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.Note M – CommitmentsThe Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2017 to 2020 natural gas sales volumes in Western Canada. During the period from October to December 2017 the natural gas sales contracts call for deliveries of 124 million cubic feet per day at Cdn $2.97 per MCF. During the period from January 2018 through December 2020 the natural gas sales contracts call for deliveries of 59 million cubic feet per day at Cdn $2.81 per MCF. During the period from November 2017 through March 2018 the natural gas sales contracts call for deliveries of 20 million cubic feet per day at US $3.51 per MCF.These natural gas contracts have been accounted for as normal sales for accounting purposes.16NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note NO – 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 reclassifications have been made to 2016 Corporate External Revenue to align with current period presentation (see Note A).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) 20*Total Assets at September 30, 2021 Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States $ 6,586.3 565.2 168.1 330.8 (172.6) Canada 2,241.2 124.6 73.9 96.3 (8.6) Other 264.6 — (5.2) — (11.7) Total exploration and production 9,092.1 689.8 236.8 427.1 (192.9) Corporate 1,237.8 (59.1) (98.8) (5.2) (72.9) Continuing operations 10,329.9 630.7 138.0 421.9 (265.8) Discontinued operations, net of tax 1.0 — (0.7) — (0.8) Total $ 10,330.9 630.7 137.3 421.9 (266.6) Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States 1,704.4 481.8 1,070.6 (1,011.7) Canada 349.2 (37.7) 245.2 (35.0) Other — (22.5) 1.8 (73.0) Total exploration and production 2,053.6 421.6 1,317.6 (1,119.7) Corporate (493.3) (577.6) 319.5 26.9 Continuing operations 1,560.3 (156.0) 1,637.1 (1,092.8) Discontinued operations, net of tax — (0.6) — (6.9) Total 1,560.3 (156.6) 1,637.1 (1,099.7) 1Additional details about results of oil and natural gas operations are presented in the tablestable on pages 2925 and 30.Note O – New Accounting Principles AdoptedBusiness Combinations21SummaryIn January 2017,2021, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definitionglobal distribution and administration of a business to assist entitiesvaccinations 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.17NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note O – New Accounting Principles Adopted (Contd.)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.Note P – Recent Accounting PronouncementsCompensation – Stock CompensationIn 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 changesresponse to the termsongoing coronavirus disease 2019 (COVID-19) pandemic has led to an improving global economic outlook and conditionssubsequently increased demand for oil and gas. Emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the outlook, however in 2021 demand for oil and gas has remained resilient. The demand resilience has revealed an oil supply shortage, and hence is applying upward pressure to current and future oil and gas prices.The OPEC+ group of share-based payment awardsoil producing countries (OPEC+) continues to which an entity would be requiredtarget increasing supply by 0.4 million bpd a month, with aims to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods withinfully phase out prior cuts by September 2022, at the annual period. Early adoption is permitted. The Company does not believecurrent rate of OPEC+ supply increases. In 2020 OPEC+ cut production by 10 million barrels per day (bpd) following 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 requiringCOVID-19 demand reduction. It has gradually reinstated supply so that the service cost componentcurtailments are approximately 5.8 million bpd at the end 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 presentationSeptember 2021. However, some members of the componentsOPEC+ are falling short on supply increases.Overall, the combination of these benefit costsOPEC+ supply constraints and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believeincrease in demand driven by 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 Companyglobal COVID-19 vaccine roll out 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.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.18NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note P – Recent Accounting Pronouncements (Contd.)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 relationprovided upward pressure to the effective interest rate ofoil price which directly impacts the borrowing, contingent consideration payments made after a business combination, proceedsCompany’s product revenue 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.During 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.2017,2021, West Texas Intermediate (WTI) crude oil prices averaged approximately $70.56 per barrel (compared to $66.07 in the second quarter of 2021 and $40.93 in the third quarter of 2020). The closing price for WTI at the end of the third quarter of 2021 was approximately $71.54 per barrel, reflecting a modest increase from the second quarter 2021 closing price and an 81% increase from the third quarter 2020 closing price. The average price in October 2021 was $81.22 per barrel. As of close on November 2, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $83.91 and $76.27 per barrel, respectively.In the third quarter of 2021, the Company continued to delever by redeeming $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 for the principal amount plus cash costs of $2.6 million. Earlier in 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which included redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and closing costs of $8.1 million. The proceeds from issue are reported net of costs to issue on the Consolidated Balance Sheets.In the third quarter of 2021, the Company acquired an additional 7.525% working interest at Terra Nova in Canada following a commercial agreement to sanction an asset life extension project. This transaction deferred an asset obligation at Terra Nova by approximately 10 years and decreased the obligation associated with the abandonment liability of the working interest before the acquisition by approximately $72 million.For the three months ended September 30, 2021, the Company produced 154163 thousand barrels of oil equivalent per day. There was noday (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production in the 2017 quarter from Canadian synthetic and heavyof 14.5 thousand barrels of oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively.equivalent per day (including NCI). The Company invested $287$110.5 million in capital expenditureexpenditures (on a value of work done basis) in the third quarter of 2017 primarily in the United States and Canada.three months ended September 30, 2021. The Company reported a net lossincome from continuing operations of $65.9$138.0 million for the three months ended September 30, 2017, which included a foreign exchange2021. This amount includes income attributable to noncontrolling interest of $28.9 million, after-tax lossgains on unrealized mark to market revaluations on commodity price swap and collar positions of $43.9$44.1 million, principally on intercompany loans in the quarter and an after-tax lossnon-cash credit of $11.8$53.6 million inrelated to the third quarter relating to crude oil derivative contracts.For the nine-month periodnine months ended September 30, 2017,2021, 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 162170 thousand barrels of oil equivalent per day for(including noncontrolling interest) from continuing operations; this includes the nine-month 2017 period andimpact of Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI). The Company invested $702$568.7 million in capital expenditures principally(on a value of work done basis) in the United States and Canada.nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay Floating Production System (FPS). The Company incurred a non-cash deferred tax expenseFPS capital expenditures were reimbursed by Arclight in the first quarter of 2021 (see below). The Company reported net loss from continuing operations of $156.0 million for the nine months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of 2017$85.5 million, after-tax impairment charges of $65.2$128.0 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on earningsunrealized mark to market revaluations on commodity price swap and collar positions and contingent consideration of foreign subsidiaries,$180.5 million and $83.0 million, respectively.22For the majoritythree months ended September 30, 2020, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $122.7 million in capital expenditures (on a value of work done basis), in the third quarter of 2020, which was recordedincluded $19.3 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $265.8 million for the third quarter of 2020. This amount included loss attributable to noncontrolling interest of $23.1 million, after-tax impairment charges of $145.9 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $54.8 million and $11.1 million, respectively.For the nine months ended September 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $680.3 million in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2020, which included $80.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $1,092.8 million for the nine months ended September 30, 2020. This amount included loss attributable to noncontrolling interest of $122.9 million, after-tax impairment charges of $854.2 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $82.5 million and $23.3 million, respectively.In the first quarter, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of 2017 and recorded a foreign exchange after-tax loss of $86.6 million, principally on intercompany loansMurphy’s entire 50% interest in the first nine monthsKing’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share 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.Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2021 2020 2021 2020 33.6 25.0 276.6 (99.5) Exploration and production $ 236.8 (192.9) 421.6 (1,119.7) (99.9) (39.6) (302.8) (111.7) Corporate and other (98.8) (72.9) (577.6) 26.9 (66.3) (14.6) (26.2) (211.2) 0.4 (1.6) 1.2 (0.8) (65.9) (16.2) (25.0) (212.0) Income (loss) from continuing operations Income (loss) from continuing operations 138.0 (265.8) (156.0) (1,092.8) Discontinued operations ¹ Discontinued operations ¹ (0.7) (0.8) (0.6) (6.9) Net income (loss) including noncontrolling interest Net income (loss) including noncontrolling interest $ 137.3 (266.6) (156.6) (1,099.7) 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 impacted19ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Nine months 2017 vs. 2016 (contd.)by higher revenues due to higher realized oil 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 selling 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, higher 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 compared to a loss of $0.8 million ($0.01 per diluted share) 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 and 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 6:123ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (Contd.)Exploration and Production (Contd.)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 1U.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 offset 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 OperationsExploration and ProductionResults of E&P continuing operations are presented by geographic segment below.Income (Loss) Three Months Ended
September 30,Nine Months Ended September 30, (Millions of dollars) 2021 2020 2021 2020 Exploration and production United States $ 168.1 (172.6) 481.8 (1,011.7) Canada 73.9 (8.6) (37.7) (35.0) Other (5.2) (11.7) (22.5) (73.0) Total $ 236.8 (192.9) 421.6 (1,119.7) 23ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Other key performance metricsThe after-taxCompany 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 income (loss) 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
September 30,Nine Months Ended
September 30,(Millions of dollars, except per barrel of oil equivalents sold) 2021 2020 2021 2020 Net income (loss) attributable to Murphy (GAAP) $ 108.5 (243.6) (242.1) (976.8) Income tax expense (benefit) 36.8 (62.6) (62.5) (248.9) Interest expense, net 46.9 45.2 178.4 124.9 Depreciation, depletion and amortization expense ¹ 182.8 219.7 588.4 725.1 EBITDA attributable to Murphy (Non-GAAP) 375.0 (41.3) 462.2 (375.7) Mark-to-market (gain) loss on derivative instruments (55.9) 69.3 228.5 (104.5) Impairment of assets ¹ — 186.5 171.3 1,072.5 Mark-to-market loss (gain) on contingent consideration 28.4 14.0 105.1 (29.5) Asset retirement obligation (gains) losses (71.8) — (71.8) — Accretion of asset retirement obligations ¹ 10.8 10.8 30.8 31.2 Unutilized rig charges 3.2 5.2 8.5 13.2 Foreign exchange (gains) losses (2.8) 0.8 (1.5) (2.5) Discontinued operations loss 0.7 0.8 0.6 6.9 Restructuring expenses — 5.0 — 46.4 Inventory loss — — — 4.8 Seal insurance proceeds — (1.7) — (1.7) Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 287.6 249.4 933.7 661.1 Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 14,219 14,166 43,536 46,478 Adjusted EBITDA per barrel of oil equivalents sold $ 20.23 17.61 21.45 14.22 1 Depreciation, depletion, and amortization expense, impairment of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.24ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020(Millions of dollars) UnitedStates 1Canada Other Total Three Months Ended September 30, 2021 Oil and gas sales and other operating revenues $ 565.2 124.6 — 689.8 Lease operating expenses 96.7 33.4 0.1 130.2 Severance and ad valorem taxes 10.8 0.8 — 11.6 Transportation, gathering and processing 28.4 16.2 — 44.6 Depreciation, depletion and amortization 147.0 39.7 0.1 186.8 Accretion of asset retirement obligations 9.3 2.9 — 12.2 Exploration expenses Dry holes and previously suspended exploration costs 17.3 — — 17.3 Geological and geophysical — — 0.3 0.3 Other exploration 1.3 0.1 0.5 1.9 18.6 0.1 0.8 19.5 Undeveloped lease amortization 3.1 0.1 1.8 5.0 Total exploration expenses 21.7 0.2 2.6 24.5 Selling and general expenses 4.2 4.0 1.2 9.4 Other ² 39.1 (71.7) 2.0 (30.6) Results of operations before taxes 208.0 99.1 (6.0) 301.1 Income tax provisions (benefits) 39.9 25.2 (0.8) 64.3 Results of operations (excluding Corporate segment) $ 168.1 73.9 (5.2) 236.8 Three Months Ended September 30, 2020 Oil and gas sales and other operating revenues $ 330.8 96.3 — 427.1 Lease operating expenses 91.5 32.6 0.4 124.5 Severance and ad valorem taxes 6.4 0.3 — 6.7 Transportation, gathering and processing 29.3 12.0 — 41.3 Depreciation, depletion and amortization 166.2 59.6 0.5 226.3 Accretion of asset retirement obligations 9.4 1.4 — 10.8 Impairment of assets 205.1 — — 205.1 Exploration expenses Dry holes and previously suspended exploration costs 0.6 — — 0.6 Geological and geophysical 0.1 — (0.1) — Other exploration 0.6 0.1 3.6 4.3 1.3 0.1 3.5 4.9 Undeveloped lease amortization 4.9 0.1 2.3 7.3 Total exploration expenses 6.2 0.2 5.8 12.2 Selling and general expenses 5.3 3.4 1.6 10.3 Other 22.5 (1.5) 2.5 23.5 Results of operations before taxes (211.1) (11.7) (10.8) (233.6) Income tax (benefits) provisions (38.5) (3.1) 0.9 (40.7) Results of operations (excluding Corporate segment) $ (172.6) (8.6) (11.7) (192.9) 1 Includes results attributable to a noncontrolling interest in MP GOM.2 For the three months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.25ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020(Millions of dollars) United
States 1Canada Other Total Nine Months Ended September 30, 2021 Oil and gas sales and other operating revenues $ 1,704.4 349.2 — 2,053.6 Lease operating expenses 303.3 100.0 0.4 403.7 Severance and ad valorem taxes 30.6 1.6 — 32.2 Transportation, gathering and processing 90.5 46.7 — 137.2 Depreciation, depletion and amortization 476.6 128.0 1.1 605.7 Accretion of asset retirement obligations 27.5 7.4 — 34.9 Impairment of assets — 171.3 — 171.3 Exploration expenses Dry holes and previously suspended exploration costs 17.9 — — 17.9 Geological and geophysical 2.7 — 1.3 4.0 Other exploration 4.2 0.2 9.6 14.0 24.8 0.2 10.9 35.9 Undeveloped lease amortization 7.9 0.2 5.8 13.9 Total exploration expenses 32.7 0.4 16.7 49.8 Selling and general expenses 15.0 12.0 4.7 31.7 Other ² 133.5 (67.7) (1.2) 64.6 Results of operations before taxes 594.7 (50.5) (21.7) 522.5 Income tax provisions (benefits) 112.9 (12.8) 0.8 100.9 Results of operations (excluding Corporate segment) $ 481.8 (37.7) (22.5) 421.6 Nine months ended September 30, 2020 Oil and gas sales and other operating revenues $ 1,070.6 245.2 1.8 1,317.6 Lease operating expenses 386.5 90.6 1.2 478.3 Severance and ad valorem taxes 21.6 1.0 — 22.6 Transportation, gathering and processing 95.4 31.4 — 126.8 Depreciation, depletion and amortization 589.5 161.3 1.5 752.3 Accretion of asset retirement obligations 27.1 4.1 — 31.2 Impairment of assets 1,152.5 — 39.7 1,192.2 Exploration expenses Dry holes and previously suspended exploration costs 8.3 — — 8.3 Geological and geophysical 9.4 0.1 4.1 13.6 Other exploration 4.3 0.4 13.1 17.8 22.0 0.5 17.2 39.7 Undeveloped lease amortization 14.8 0.3 6.9 22.0 Total exploration expenses 36.8 0.8 24.1 61.7 Selling and general expenses 16.6 13.2 5.5 35.3 Other 1.0 (2.5) 1.4 (0.1) Results of operations before taxes (1,256.4) (54.7) (71.6) (1,382.7) Income tax provisions (benefits) (244.7) (19.7) 1.4 (263.0) Results of operations (excluding Corporate segment) $ (1,011.7) (35.0) (73.0) (1,119.7) 1 Includes results attributable to a noncontrolling interest in MP GOM.2 For the nine months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.26ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Exploration and ProductionThird quarter 2021 vs. 2020All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.United States E&P operations reported earnings of $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of 2020. Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A: $19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in the third quarter of 2020. Lower impairment charges were due to impairment charges recognized in the prior period related to Gulf of Mexico Cascade & Chinook field and no such charges in current period. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher other operating expense is primarily due to unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher exploration expense is primarily due to dry hole costs related to Silverback in the current period.Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter of 2020. Results were favorable $82.5 million compared to the 2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($28.3 million) and lower DD&A ($19.9 million), partially offset by higher tax expense ($28.3 million) and higher transportation, gathering and processing ($4.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Montney. Lower DD&A is due to lower production volumes at Kaybob Duvernay due to normal well decline. Higher transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020. The result was $6.5 million favorable in the 2021 period versus 2020 primarily due lower exploration expenses in Brazil and Mexico.Nine months 2021 vs. 2020All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020. Results were $1,493.5 million favorable in 2021 period compared to the 2020 period primarily due to no impairment charges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($633.8 million), lower DD&A ($112.9 million), lower lease operating expenses (LOE: $83.2 million), partially offset by higher income tax expense ($357.6 million) and higher other operating expense ($132.5 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in 2020. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense is primarily due to an unfavorable mark to market revaluation on contingent consideration ($105.1 million; as a result of higher commodity prices) from prior GOM acquisitions.Canadian E&P operations reported a loss of $37.7 million in the first nine months of 2021 compared to a loss of $35.0 million in the first nine months of 2020. Results were comparable year over year. 2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue ($104.0 million) and lower DD&A ($33.3 million) offset by higher transportation, gathering and processing expenses ($15.3 million) and lease operating expenses ($9.4 million). Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital27ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.Other international E&P operations reported a loss of $22.5 million in the first nine months of 2021 compared to a loss of $73.0 million in the prior year. Results were $50.5 million favorable compared to the 2020 period primarily due to no repeat of an impairment charge of $39.7 million in the prior year.CorporateThird quarter 2021 vs. 2020Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020. The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $59.2 million loss; 2020: $5.3 million loss), partially offset by lower impairment charges ($14.1 million), higher tax benefits ($5.7 million), lower restructuring charges ($5.0 million), and lower DD&A ($2.3 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.Nine months 2021 vs. 2020Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $577.6 million in the first nine months of 2021 compared to earnings of $26.9 million in the first nine months of 2020. The $604.5 million unfavorable variance is primarily due to realized and unrealized losses on derivative instruments in 2021 compared to gains in 2020 (2021: $499.8 million loss; 2020: $319.5 million gain), and higher interest expense ($54.1 million), partially offset by higher tax benefits ($177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $74.87 and for 2022 was $70.87 (versus swap contract fixed hedge prices of $42.77 and $44.88, respectively). Interest charges are higher in 2021primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022. Higher income tax benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.Production Volumes and PricesThird quarter 2021 vs. 2020Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020. U.S. Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms. The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020.Average crude oil and condensate production from continuing operations was 88,245 barrels per day in the third quarter of 2021 compared to 95,391 barrels per day in the third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to Kaybob Duvernay well decline), lower volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a28ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)worldwide basis, the Company’s crude oil and condensate prices averaged $68.88 per barrel in the third quarter 2021 compared to $39.79 per barrel in the 2020 period, an increase of 73% quarter over quarter.Total production of natural gas liquids (NGL) from continuing operations was 10,391 barrels per day in the third quarter 2021 compared to 10,523 barrels per day in the 2020 period. The average sales price for U.S. NGL was $32.01 per barrel in the 2021 quarter compared to $13.91 per barrel in 2020. The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.Natural gas production volumes from continuing operations averaged 387.5 million cubic feet per day (MMCFD) in the third quarter 2021 compared to 341.5 MMCFD in 2020. The increase of 46 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico (7 MMCFD) and in the Eagle Ford Shale (4 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Lower volumes in the Gulf of Mexico are principally due to facility shut-ins as a result of Hurricane Ida.Natural gas prices for the total Company averaged $2.78 per thousand cubic feet (MCF) in the 2021 quarter, versus $1.78 per MCF average in the same quarter of 2020. Average natural gas prices in the U.S. and Canada in the quarter were $3.99 and $2.47 per MCF, respectively.Nine months 2021 vs. 2020Total hydrocarbon production from all E&P continuing operations averaged 170,209 barrels of oil equivalent per day in the first nine months of 2021, which represented a 6% decrease from the 180,443 barrels per day produced in the first nine months of 2020. The decrease in production is principally due to lower capital expenditures throughout 2020 to support generating positive free cashflow.Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020. The decrease of 10,364 barrels per day was principally due to lower Gulf of Mexico production (5,472 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 and facility shut-ins as a result of Hurricane Ida in the third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged $64.19 per barrel in the first nine months of 2021 compared to $36.88 per barrel in the 2020 period, an increase of 74% year over year.Total production of natural gas liquids (NGL) from continuing operations was 10,498 barrels per day in the first nine months of 2021 compared to 11,901 barrels per day in the 2020 period. The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in 2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.Natural gas sales volumes from continuing operations averaged 368.4 million cubic feet per day (MMCFD) in the first nine months of 2021 compared to 359.2 MMCFD in 2020. The increase of 9.2 MMCFD was primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the first nine months of 2021, versus $1.68 per MCF average in the same period of 2020. Average natural gas prices in the U.S. and Canada in the quarter were $3.26 and $2.33, respectively.Additional details about results of theseoil and natural gas operations are presented in the tables on pages 25 and 26.29ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2021 and 2020.Three Months Ended
September 30,Nine Months Ended
September 30,Barrels per day unless otherwise noted 2021 2020 2021 2020 Continuing operations Net crude oil and condensate United States Onshore 26,193 24,851 26,552 27,945 Gulf of Mexico 153,011 56,517 61,905 67,377 Canada Onshore 4,963 9,595 5,598 8,106 Offshore 3,779 4,428 4,016 5,136 Other 299 — 243 114 Total net crude oil and condensate - continuing operations 88,245 95,391 98,314 108,678 Net natural gas liquids United States Onshore 5,847 5,489 5,043 5,459 Gulf of Mexico 13,459 3,521 4,296 5,131 Canada Onshore 1,085 1,513 1,159 1,311 Total net natural gas liquids - continuing operations 10,391 10,523 10,498 11,901 Net natural gas – thousands of cubic feet per day United States Onshore 31,478 27,520 27,750 29,054 Gulf of Mexico 146,339 53,046 63,557 67,850 Canada Onshore 309,709 260,895 277,077 262,279 Total net natural gas - continuing operations 387,526 341,461 368,384 359,183 Total net hydrocarbons - continuing operations including NCI 2,3163,224 162,824 170,209 180,443 Noncontrolling interest Net crude oil and condensate – barrels per day (7,546) (9,298) (8,834) (10,674) Net natural gas liquids – barrels per day (243) (327) (322) (443) Net natural gas – thousands of cubic feet per day 2(2,331) (3,269) (3,498) (4,137) Total noncontrolling interest (8,178) (10,170) (9,739) (11,807) Total net hydrocarbons - continuing operations excluding NCI 2,3155,046 152,654 160,470 168,636 1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).2 Natural gas converted on an energy equivalent basis of 6:13 NCI – noncontrolling interest in MP GOM.30ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 20172021 and 20162020.Comparative periods are reflected inconformed to current presentation.Three Months Ended
September 30,Nine Months Ended
September 30,2021 2020 2021 2020 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore 69.30 37.83 64.16 35.56 Gulf of Mexico 168.93 40.82 64.44 38.08 Canada 2Onshore 63.76 36.65 58.70 30.29 Offshore 72.64 43.81 68.93 37.85 Other — — — 63.51 Natural gas liquids – dollars per barrel United States Onshore 30.37 13.39 24.29 10.78 Gulf of Mexico 134.71 14.71 27.17 9.43 Canada 2Onshore 45.12 19.97 37.05 16.95 Natural gas – dollars per thousand cubic feet United States Onshore 3.85 1.78 3.23 1.76 Gulf of Mexico 14.09 2.01 3.28 1.91 Canada 2Onshore 2.47 1.74 2.33 1.62 1Prices include the following table.effect of noncontrolling interest share for MP GOM.(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 ConditionCash Provided by Operating ActivitiesNet cash provided by continuing operating activities was $819.6$1,091.3 million for the first nine months of 20172021 compared to $280.3$578.0 million during the same period in 2016.2020. The improvement inincreased cash provided by continuing operationsfrom operating activities in 2017 wasis primarily attributable to higher realizedrevenue from sales prices for the Company’s oil and gas production,to customers ($727.3 million), lower working capital ($143.6 million), lower lease operating expense ($74.6 million), and lower general and administrative expenses, and rig cancellation payments in 2016 which are discussed below,cash restructuring expense ($47.4 million), partially offset by lower volume sold in the current year and higher interest costs. Changes in operating working capital from continuing operations increased cash payments made on forward swap commodity contracts (2021: realized loss of $271.3 million; 2020: realized gain of $215.0 million).Cash Required by $1.1Investing ActivitiesNet cash required by investing activities was $311.9 million duringfor the first nine months of 2017,2021 compared to a use of cash of $152.6$723.7 million during the same period 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.27ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Financial Condition (Contd.)Cash used for property2020. Property additions and dry holes,hole costs, which includes amounts expensed, were $706.4$582.0 million and $781.7$723.7 million in the nine-month period ended September 30, 2017first nine months of 2021 and 2016,2020, respectively. Total cash dividendsThese amounts include $17.7 million and $74.9 million used to shareholders amounted to $129.4 million forfund the nine-months ended September 30, 2017 compared to $163.6 milliondevelopment of the King’s Quay FPS in the same periodfirst nine months of 2016 as2021 and 2020, respectively. In the Company loweredfirst quarter of 2021, the dividend from $1.40 per shareKing’s Quay FPS was sold 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. TheArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the $550 million notes issuedCompany for previously incurred capital expenditures. Lower property additions in August 2017, were used2021 are principally due to redeem the Company’s $550 million 2.50% notes in September 2017. The 2.50% notes had a maturity datelower capital spending at Eagle Ford Shale and lower spend on King’s Quay.31ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)Financial Condition (contd.)Total accrual basis capital expenditures were as follows:Nine Months Ended
September 30,(Millions of dollars) 2021 2020 Capital Expenditures 694.7 614.6 Exploration and production $ 556.0 671.0 6.9 20.7 Corporate 12.7 9.3 701.6 635.3 Total capital expenditures $ 568.7 680.3 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.Nine Months Ended
September 30,(Millions of dollars) 2021 2020 706.4 781.7 Property additions and dry hole costs per cash flow statements $ 564.2 648.7 Property additions King's Quay per cash flow statements Property additions King's Quay per cash flow statements 17.7 74.9 37.7 32.8 Geophysical and other exploration expenses 13.3 26.8 (42.5) (179.2) Capital expenditure accrual changes and other (26.6) (70.2) 701.6 635.3 Total capital expenditures $ 568.7 680.3 Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of capital expenditure reductions to support generating positive free cash flow.Cash Used in/ Provided by Financing ActivitiesNet cash required by financing activities was $585.6 million for the first nine months of 2021 compared to net cash provided by financing activities of $59.1 million during the same period in 2020. In 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($450.0 million), offset by repayments on the revolving credit facility ($250.0 million), cash dividends to shareholders ($76.8 million), and distributions to our noncontrolling interest ($43.7 million).Working CapitalWorking capital (total current assets less total current liabilities)liabilities – excluding assets and liabilities held for sale) at September 30, 20172021 was $615.6a deficit of $344.9 million, $558.8$315.5 million morelower than December 31, 2016,2020, with the increasedecrease primarily attributable to the Company redeeming the $550 million in 2.50% notes in September 2017,higher accounts payable ($208.3 million), higher other accrued liabilities ($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a higher cash balancesbalance ($194.5 million) and lower accounts payable.32Capital EmployedAt September 30, 2017,2021, long-term debt of $2,908.3$2,613.7 million had increaseddecreased by $485.5$374.4 million compared to December 31, 2016. 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.A summary of capital employed at September 30, 20172021 and December 31, 20162020 follows.September 30, 2021 December 31, 2020 (Millions of dollars) Amount % Amount % Capital employed 2,908.3 36.9 2,422.8 33.0 Long-term debt $ 2,613.7 39.8 % $ 2,988.1 41.5 % 4,980.1 63.1 4,916.7 67.0 Murphy shareholders' equity Murphy shareholders' equity 3,949.5 60.2 % 4,214.3 58.5 % 7,888.4 100.0 7,339.5 100.0 Total capital employed $ 6,563.2 100.0 % $ 7,202.4 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2017,2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5$119.4 million in Canada and $261.6$6.2 million in Malaysia. In addition, $17.0 million of cash was held in the United Kingdom, but was reflected in current Assets Held for Sale on the Company’s Consolidated Balance Sheet at September 30, 2017.Brunei. 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 dividendU.S.Accounting changes and recent accounting pronouncements – see Note B to the U.S. parent. SeeConsolidated Financial StatementsOutlookAs discussed in 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)23, average crude oil prices continued 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 optionsrecover during the period.In May 2017, FASB issued an ASU which amendssecond half of 2021 versus 2020 (Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93). As of close on November 2, 2021, 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 retrospectiveNYMEX WTI forward curve price for the presentationremainder of 2021 and 2022 were $83.91 and $76.27 per barrel, respectively; however we cannot predict what impact economic factors (including the components of these benefit costsongoing COVID-19 pandemic 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 ASUOPEC+ decisions) may have on its consolidated financial statements.Statement of Cash FlowsIn August 2016, the FASB issued an ASU to reduce diversityfuture commodity pricing. Lower prices, should they occur, will result 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,lower profits 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 worldwide crude oil prices in October 2017 have slightly improved from the average prices during the third quarter of 2017. North American natural gas prices decreased slightly in October from the 2017 third quarter. The Company expects its total oil and natural gas production to average 170,000 – 172,000 barrels of oil equivalent per day inoperating cash-flows. For the fourth quarter, 2017. production is expected to average between 145.5 and 153.5 MBOEPD, excluding noncontrolling interest (NCI).The Company currently anticipates totalCompany’s capital expenditure spend for 2021 is expected to be between $675.0 million and $685.0 million. Capital and other expenditures are routinely reviewed and planned capital expenditures formay be adjusted to reflect differences between budgeted and forecast cash flow during the full year 2017 toyear. Capital expenditures may also be approximately $940 million.20172021 using operating cash flow but will supplement funding where necessary using borrowings underand available credit facilities.cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the remainder of year to maintain funding of the Company’s ongoing development projects. The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt.The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the progress of the vaccination roll-outs globally.As of November 1, 2017,2, 2021, 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:Contract orAverageCommoditiesLocationDatesVolumes per DayAverage PricesU.S. OilWest Texas IntermediateOct. – Dec. 201722,000 bbls/d$50.41 per bbl.U.S. OilWest Texas IntermediateJan. – Dec. 20187,000 bbls/d$51.92 per bbl.Natural GasTCPL–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*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 $42.77 10/1/2021 12/31/2021 United States WTI ¹ Fixed price derivative swap 20,000 $44.88 1/1/2022 12/31/2022 *Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate.28Volumes
(Bbl/d)Average
Put
(USD/Bbl)Average
Call
(USD/Bbl)Remaining Period Area Commodity Type Start Date End Date United States WTI ¹ Derivative collars 23,000 $62.652 $74.774 1/1/2022 12/31/2022 1 West Texas Intermediate33Volumes
(MMcf/d)Price/Mcf Remaining Period Area Commodity Type Start Date End Date Montney Natural Gas Fixed price forward sales 196 C$2.55 10/1/2021 12/31/2021 Montney Natural Gas Fixed price forward sales 186 C$2.36 1/1/2022 1/31/2022 Montney Natural Gas Fixed price forward sales 176 C$2.34 2/1/2022 4/30/2022 Montney Natural Gas Fixed price forward sales 205 C$2.34 5/1/2022 5/31/2022 Montney Natural Gas Fixed price forward sales 247 C$2.34 6/1/2022 10/31/2022 Montney Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022 Montney Natural Gas Fixed price forward sales 269 C$2.35 1/1/2023 3/31/2023 Montney Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023 Montney Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024 Montney Natural Gas Fixed price forward sales 45 US$2.05 10/1/2021 12/31/2022 Montney Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024 Montney Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 Forward-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 20162020 Annual Report on Form 10-K on file with the U.S. Securities and3637 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.34ITEM 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 September 30, 20172021, covering certain future U.S. crude oil sales volumes in 2017.2021 and 2022. A 10% increase in the respective benchmark price of these commodities would have decreasedincreased the recorded net receivablepayable associated with these derivative contracts by approximately $21.9$113.6 million, while a 10% decrease would have increaseddecreased the recorded net receivablepayable by a similar amount.There were no derivative foreign exchange contracts in place at September 30, 2017.2021.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 September 30, 2017,2021, 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.35Murphy 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 natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 20162020 Form 10-K filed on February 24, 2017.26, 2021. The Company has not identified any additional risk factors not previously disclosed in its 20162020 Form 10-K report.The Exhibit Index on page 3839 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.36SIGNATUREPursuant 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)EXHIB(Date)37EXHIBIT INDEXThe following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.Exhibit
No.Exhibit No. *31.2 *32 Exhibits other than those listed above have been omitted since they are either not required or not applicable.2938