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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 $ current period presentation. 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 $ contract assets arising from customer contracts during the reporting periods. (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 – $ $ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) net of closing adjustments. 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 $ The 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. 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, 2022. 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% noncontrolling interest in MP GOM. rate on income. an overall loss. rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate. Foreign Currency Exchange Risks 2022 and 2021. 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 $ 2022. 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. quarter of 2022 as compared to the same period in 2021, principally due to demand recovery from COVID-19 and geopolitical uncertainty and market disruption following the Russian invasion of Ukraine. Prices were lower in the third quarter 2022 as compared to the second quarter of 2022 primarily due to increased supply related to the Strategic Petroleum Reserve oil release in the third quarter, ongoing concerns related to possible economic slowdown and lower demand from China. of 2022, the Company reduced debt by $247.6 million aggregate principal amount of its 6.875%, 5.750%, 6.375%, 6.125% senior notes due 2024, 2025, 2028, 2042 for the principal amount plus cash costs of $2.0 million. In 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and partially redeemed the 2024 Notes. 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 $ ITEM 2. Nine Months Ended September 30, (Millions of dollars) 2017 2016 Capital Expenditures Exploration and production $ Corporate Total capital expenditures $ Nine Months Ended September 30, (Millions of dollars) 2017 2016 Property additions and dry hole costs per cash flow statements $ Geophysical and other exploration expenses Capital expenditure accrual changes and other Total capital expenditures $ payable ($83.6 million), partially offset by higher other accrued liabilities ($74.9 million), a lower cash balance ($55.2 million) and higher operating lease liabilities ($27.5 million). Higher accounts receivable are principally due to higher crude oil and gas pricing. Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the September 30, 2017 December 31, 2016 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ % $ % Stockholders' equity % % Total capital employed $ % $ % any Canada Canada Canada Exchange Commission and on page 36 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements. By Vaughan 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 2022was 172,572,873.155,455,283.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,
2022December 31,
2021ASSETS Current assets Cash and cash equivalents $ 465,998 521,184 Accounts receivable, net 385,153 258,150 Inventories 53,265 54,198 Prepaid expenses 39,633 31,925 Assets held for sale 7,538 15,453 Total current assets 951,587 880,910 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,220,651 in 2022 and $12,457,851 in 2021 8,249,387 8,127,852 Operating lease assets 798,119 881,389 Deferred income taxes 196,894 385,516 Deferred charges and other assets 33,227 29,273 Total assets $ 10,229,214 10,304,940 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 678 654 Accounts payable 539,576 623,129 Income taxes payable 38,701 19,951 Other taxes payable 30,898 20,306 Operating lease liabilities 166,908 139,427 Other accrued liabilities 435,740 360,859 Total current liabilities 1,212,501 1,164,326 Long-term debt, including finance lease obligation 2,022,976 2,465,414 Asset retirement obligations 848,607 839,776 Deferred credits and other liabilities 429,200 570,574 Non-current operating lease liabilities 648,286 761,162 Deferred income taxes 188,046 182,892 Total liabilities 5,349,616 5,984,144 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 2022 and 195,100,628 shares in 2021 195,101 195,101 Capital in excess of par value 887,730 926,698 Retained earnings 5,894,965 5,218,670 Accumulated other comprehensive loss (653,828) (527,711) Treasury stock (1,615,027) (1,655,447) Murphy Shareholders' Equity 4,708,941 4,157,311 Noncontrolling interest 170,657 163,485 Total equity 4,879,598 4,320,796 Total liabilities and equity $ 10,229,214 10,304,940 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) 2022 2021 2022 2021 Revenues and other income Revenues and other income Revenue from production Revenue from production $ 1,120,909 687,549 $ 3,101,736 2,038,905 Sales of purchased natural gas Sales of purchased natural gas 45,500 — 132,285 — Total revenue from sales to customers Total revenue from sales to customers 1,166,409 687,549 3,234,021 2,038,905 Gain (Loss) on derivative instruments Gain (Loss) on derivative instruments 115,191 (59,164) (308,654) (499,794) Gain on sale of assets and other income Gain on sale of assets and other income 21,825 2,315 32,076 21,217 Total revenues and other income Total revenues and other income 1,303,425 630,700 2,957,443 1,560,328 Costs and expenses 112,751 119,663 346,072 435,296 Lease operating expenses 198,710 130,131 482,887 403,708 10,816 9,592 32,771 35,668 Severance and ad valorem taxes 15,140 11,670 47,340 32,215 28,492 19,866 77,356 83,910 Transportation, gathering and processing Transportation, gathering and processing 55,348 44,588 152,219 137,196 Costs of purchased natural gas Costs of purchased natural gas 43,622 — 125,258 — Exploration expenses, including undeveloped lease amortization Exploration expenses, including undeveloped lease amortization 9,491 24,517 72,208 49,840 56,672 55,523 168,259 196,143 Selling and general expenses 29,348 27,210 90,007 85,826 243,636 255,900 714,782 797,288 Depreciation, depletion and amortization 214,521 189,806 574,501 615,372 10,654 11,043 31,638 35,514 Accretion of asset retirement obligations 11,286 12,198 34,725 34,854 95,088 Impairment of assets — — — 171,296 2,454 6,486 10,988 (1,446) Other operating (income) expense Other operating (income) expense (27,129) (32,791) 115,726 58,616 465,475 478,073 1,381,866 1,677,461 Total costs and expenses 550,337 407,329 1,694,871 1,588,923 32,844 7,473 301,372 (347,773) Operating income (loss) from continuing operations 753,088 223,371 1,262,572 (28,595) Other income (loss) (47,721) 14,987 (93,524) 38,602 Other income (expense) Other income (expense) 18,301 (1,593) 21,114 (11,459) (48,681) (39,219) (138,423) (103,889) Interest expense, net (37,440) (46,925) (116,102) (178,399) (96,402) (24,232) (231,947) (65,287) Total other loss (19,139) (48,518) (94,988) (189,858) (63,558) (16,759) 69,425 (413,060) Income (loss) from continuing operations before income taxes 733,949 174,853 1,167,584 (218,453) 2,760 (2,176) 95,602 (201,897) Income tax expense (benefit) 159,451 36,838 247,574 (62,498) (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 574,498 138,015 920,010 (155,955) Loss from discontinued operations, net of income taxes Loss from discontinued operations, net of income taxes (422) (706) (1,916) (600) Net income (loss) including noncontrolling interest Net income (loss) including noncontrolling interest 574,076 137,309 918,094 (156,555) Less: Net income attributable to noncontrolling interest Less: Net income attributable to noncontrolling interest 45,648 28,853 152,445 85,509 NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 528,428 108,456 $ 765,649 (242,064) INCOME (LOSS) PER COMMON SHARE – BASIC (0.38) (0.08) (0.15) (1.23) Continuing operations $ 3.40 0.70 $ 4.94 (1.57) (0.01) 0.01 (0.01) Discontinued operations — — (0.01) — (0.38) (0.09) (0.14) (1.24) Net income (loss) Net income (loss) $ 3.40 0.70 $ 4.93 (1.57) INCOME (LOSS) PER COMMON SHARE – DILUTED (0.38) (0.08) (0.15) (1.23) Continuing operations $ 3.36 0.70 $ 4.87 (1.57) (0.01) 0.01 (0.01) Discontinued operations — — (0.01) — (0.38) (0.09) (0.14) (1.24) Net income (loss) Net income (loss) $ 3.36 0.70 $ 4.86 (1.57) 0.25 0.25 0.75 0.95 Cash dividends per Common share $ 0.250 0.125 $ 0.575 0.375 Average Common shares outstanding (thousands) 172,573 172,199 172,509 172,165 Basic 155,446 154,439 155,221 154,239 172,573 172,199 172,509 172,165 Diluted 157,336 155,932 157,407 154,239 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) 2022 2021 2022 2021 Net income (loss) including noncontrolling interest $ 574,076 137,309 $ 918,094 (156,555) Other comprehensive (loss) income, net of tax Net (loss) gain from foreign currency translation (102,266) (31,308) (135,791) 6,534 Retirement and postretirement benefit plans 3,165 4,653 9,674 12,935 Deferred loss on interest rate hedges reclassified to interest expense — — — 1,690 Other comprehensive (loss) income (99,101) (26,655) (126,117) 21,159 Comprehensive income (loss) including noncontrolling interest $ 474,975 110,654 $ 791,977 (135,396) Less: Comprehensive income attributable to noncontrolling interest 45,648 28,853 152,445 85,509 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 429,327 81,801 $ 639,532 (220,905) See Notes to Consolidated Financial Statements, page 7.7.4CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)(Thousands 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 Nine Months Ended
September 30,(Thousands of dollars) 2022 2021 Operating Activities Net income (loss) including noncontrolling interest $ 918,094 (156,555) Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities Loss from discontinued operations 1,916 600 Depreciation, depletion and amortization 574,501 615,372 Unsuccessful exploration well costs and previously suspended exploration costs 35,224 17,899 Amortization of undeveloped leases 10,651 13,872 Accretion of asset retirement obligations 34,725 34,854 Deferred income tax (benefit) expense 207,105 (65,149) Mark to market loss on contingent consideration 98,451 105,111 Mark to market loss (gain) on crude contracts (138,707) 228,497 Long-term non-cash compensation 57,612 42,080 Impairment of assets — 171,296 (Gain) from sale of assets (18,871) — Net (increase) decrease in noncash working capital (59,874) 117,330 Other operating activities, net (42,101) (33,924) Net cash provided by continuing operations activities 1,678,726 1,091,283 Investing Activities Property additions and dry hole costs 1(800,868) (541,324) Acquisition of oil and gas properties 1(125,602) (22,906) Proceeds from sales of property, plant and equipment (2,129) 270,038 Property additions for King's Quay FPS — (17,734) Net cash (required) by investing activities (928,599) (311,926) Financing Activities Borrowings on revolving credit facility 300,000 165,000 Repayment of revolving credit facility (300,000) (365,000) Retirement of debt (446,032) (726,358) Debt issuance, net of cost — 541,913 Early redemption of debt cost (5,419) (36,756) Distributions to noncontrolling interest (145,273) (100,880) Contingent consideration payment (81,742) — Cash dividends paid (89,354) (57,896) Withholding tax on stock-based incentive awards (17,338) (4,973) Capital lease obligation payments (475) (643) Net cash (required) by financing activities (785,633) (585,593) Cash Flows from Discontinued Operations Operating activities (14,500) — Net cash (required) by discontinued operations (14,500) — Effect of exchange rate changes on cash and cash equivalents (5,180) 697 Net (decrease) increase in cash and cash equivalents (55,186) 194,461 Cash and cash equivalents at beginning of period 521,184 310,606 Cash and cash equivalents at end of period $ 465,998 505,067 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 atdate of acquisition.See Notes to Consolidated Financial Statements, page 7.7.5CONSOLIDATED 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) 2022 2021 2022 2021 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, 2022 and 195,100,628 shares at September 30, 2021Balance at beginning of period 195,101 195,101 195,101 195,101 Exercise of stock options — — — — Balance at end of period 195,101 195,101 195,101 195,101 Capital in Excess of Par Value Balance at beginning of period 883,368 915,181 926,698 941,692 Exercise of stock options, including income tax benefits (1,956) (35) (12,591) (661) Restricted stock transactions and other — (402) (45,169) (38,749) Share-based compensation 6,318 6,483 18,792 18,945 Balance at end of period 887,730 921,227 887,730 921,227 Retained Earnings Balance at beginning of period 5,405,400 4,980,428 5,218,670 5,369,538 Net income (loss) attributable to Murphy 528,428 108,456 765,649 (242,064) Cash dividends paid (38,863) (19,306) (89,354) (57,896) Balance at end of period 5,894,965 5,069,578 5,894,965 5,069,578 Accumulated Other Comprehensive Loss Balance at beginning of period (554,727) (553,519) (527,711) (601,333) Foreign currency translation (loss) gain, net of income taxes (102,266) (31,308) (135,791) 6,534 Retirement and postretirement benefit plans, net of income taxes 3,165 4,653 9,674 12,935 Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes — — — 1,690 Balance at end of period (653,828) (580,174) (653,828) (580,174) Treasury Stock Balance at beginning of period (1,616,340) (1,656,591) (1,655,447) (1,690,661) Awarded restricted stock, net of forfeitures — 343 32,297 33,888 Exercise of stock options 1,313 24 8,123 549 Balance at end of period – 39,645,345 shares of Common Stock in 2022 and 40,656,661 shares of Common Stock in 2021, at cost (1,615,027) (1,656,224) (1,615,027) (1,656,224) Murphy Shareholders’ Equity 4,708,941 3,949,508 4,708,941 3,949,508 Noncontrolling Interest Balance at beginning of period 175,428 161,228 163,485 179,810 Net income attributable to noncontrolling interest 45,648 28,853 152,445 85,509 Distributions to noncontrolling interest owners (50,419) (25,642) (145,273) (100,880) Balance at end of period 170,657 164,439 170,657 164,439 Total Equity $ 4,879,598 4,113,947 $ 4,879,598 4,113,947 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)(the Company or Murphy) 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 two 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 as Murphy is not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, 2022, our maximum exposure to loss was $3.2 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, 20172022 and December 31, 2016,2021, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 20172022 and 2016,2021, 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 2021 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, 20172022, are not necessarily indicative of future results.BeginningNote B – New Accounting Principles and Recent Accounting PronouncementsAccounting Principles AdoptedIncome Taxes. In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three 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 Gulf of Mexico, LLC (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 (GOM). 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. The Company also purchases natural gas in Canada to meet certain sales commitments.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note C – Revenue from Contracts with Customers(Contd.)Disaggregation of RevenueThe Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.For the three-month periods ended September 30, 2017, certain reclassifications in presentation have been made2022, and 2021, the Company recognized $1,166 million and $687.5 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.For the nine-month periods ended September 30, 2022, and 2021, the Company recognized $3,234.0 million and $2,038.9 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.Three Months Ended
September 30,Nine Months Ended
September 30,(Thousands of dollars) 2022 2021 2022 2021 Net crude oil and condensate revenue United States Onshore $ 247,562 167,010 $ 684,099 464,767 Offshore 597,242 340,001 1,675,389 1,079,418 Canada Onshore 29,445 29,110 106,559 89,708 Offshore 30,030 20,499 97,216 70,333 Other 4,867 — 18,503 — Total crude oil and condensate revenue 909,146 556,620 2,581,766 1,704,226 Net natural gas liquids revenue United States Onshore 18,288 16,356 53,035 33,480 Offshore 16,079 11,046 48,151 31,866 Canada Onshore 4,932 4,501 14,800 11,728 Total natural gas liquids revenue 39,299 31,903 115,986 77,074 Net natural gas revenue United States Onshore 21,009 11,127 51,412 24,442 Offshore 52,143 17,444 121,911 56,855 Canada Onshore 99,312 70,455 230,661 176,308 Total natural gas revenue 172,464 99,026 403,984 257,605 Revenue from production 1,120,909 687,549 3,101,736 2,038,905 Sales of purchased natural gas United States Offshore — — 181 — Canada Onshore 45,500 — 132,104 — Total sales of purchased natural gas 45,500 — 132,285 — Total revenue from sales to customers 1,166,409 687,549 3,234,021 2,038,905 Gain (Loss) on derivative instruments 115,191 (59,164) (308,654) (499,794) Gain on sale of assets and other income 21,825 2,315 32,076 21,217 Total revenues and other income $ 1,303,425 630,700 $ 2,957,443 1,560,328 In 2022, the Company included additional line items on the face of the Consolidated Statements of Operations. The Company now presentsOperations to report Sales of purchased natural gas and Costs of purchased natural gas. Sales and purchases of natural gas are reported on a separate “Operating income (loss)gross basis when Murphy takes control of the products and has risks and rewards of ownership.Contract Balances and Asset RecognitionAs of September 30, 2022, and December 31, 2021, receivables from continuing operations” subtotalcontracts 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 $210.1 million and $169.8 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did9NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note C – Revenue from continuing operations,Contracts with Customers(Contd.)not recognize any impairment losses on receivables or Net Loss.The Company has not entered into any revenue contracts that have financing components as of September 30, 2022.The Company does not employ sales incentive strategies such as commissions or 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.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, 2022, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:Current Long-Term Contracts Outstanding at September 30, 2022 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGL Q2 2023 Deliveries from dedicated acreage in Eagle Ford As produced 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 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 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 Contracts to sell natural gas at USD index pricing 49 MMCFD Canada NGL Q3 2023 Contracts to sell natural gas liquids at CAD pricing 952 BOED Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.Note BD – 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.At10NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note D – Property, Plant and Equipment (Contd.)As of September 30, 2017,2022, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4$181.5 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 20172022 and 2016.2021.(Thousands of dollars) 2022 2021 148,500 130,514 Beginning balance at January 1 $ 179,481 181,616 51,614 847 Additions pending the determination of proved reserves 22,275 5,007 (13,370) (8,360) Capitalized exploratory well costs charged to expense (20,295) — (3,205) 178,384 128,156 Balance at September 30 $ 181,461 186,623 The capitalized well costs charged to expense during 2022 represent expenditures related to the first nine months of 2017 included the Marakas-01Cutthroat-1 exploration well in Block SK314A,block SEAL-M-428 in the Sergipe-Alagoas Basin offshore MalaysiaBrazil. There were no hydrocarbons found 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.this well.6NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note B – Property, Plant and Equipment (Contd.)September 30, 2022 2021 (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 $ 8,851 2 2 3,297 2 2 8,430 2 2 53,101 3 3 One to two years 8,489 2 2 — — — 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 164,121 6 3 130,248 6 — 178,384 13 6 128,156 11 5 $ 181,461 10 7 186,623 13 7 Of the $136.8$172.6 million of exploratory well costs capitalized more than one year at September 30, 2017, $70.42022, $95.5 million is in Vietnam, $54.9 million is in the U.S., $15.5 million is in Mexico, $2.8 million is in Brunei, $43.2and $3.9 million is in Vietnam and $23.2 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. DivestmentsImpairmentsThere were no impairments in the first nine months of 2022. In January 2017,the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with partners, of operating and production plans at end of the first quarter 2021. Later in 2021, the Company sanctioned an asset life extension project and acquired an additional 7.525% working interest at Terra Nova following a Canadian subsidiarycommercial agreement to extend the life of the field.DivestmentsDuring the third quarter of 2022, the Company completed itsthe disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closingits 62.5% operated working interest of the transaction was approximately $49.0Thunder Hawk field for a purchase price of $20.0 million, less closing adjustments of $22.2 million, resulting in a total net payment to the buyer of $2.2 million. Additionally, the buyer assumed the asset retirement obligationobligations of approximately $85.9$47.9 million. A $132.4An $18.8 million pretax gain on sale was reportedrecorded in the first quarter of 2017period related to the sale. Also in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately $19.4 million. There were no gains or losses recorded related to these sales. During the secondthird quarter, 2016, a Canadian subsidiary of the Company completed the saledisposition of its five percent, non-operatedthe CA-2 asset in Brunei for contingent consideration valued at approximately $8.7 million. No gain or loss was recorded related to this sale.During the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the Company for previously incurred capital expenditures.AcquisitionsIn August 2022, the Company acquired an additional 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 million3.37% in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.During the second quarter 2016,Lucius field for a Canadian subsidiarypurchase price of $77.1 million, net of closing adjustments.In June 2022, the Company completed a divestitureacquired an additional working interest of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields11.0% in the Tupper areaKodiak field for a purchase price of northeastern British Columbia. A gain on sale$48.5 million, net 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 closing adjustments.117Note BD – Property, Plant and Equipment (Contd.)ImpairmentsDeclines in future oil and gas prices in early 2016 led to impairments in certain of the Company’s producing properties and the nine-month period in 2016 included pretax non-cash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal. 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. See also Note J.OtherThe Company has an interest in the Kakap field in Block K Malaysia. The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others. As required by the agreements governing the field, a redetermination (unitization) review was required in 2016. In the fourth quarter 2016, the Company recorded $39.1 million in redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, PETRONAS officially approved the redetermination that reduced the Company’s working interest from 8.6% to approximately 6.7% effective April 1, 2017. The Company partially settled $21.8 million of the redetermination expense in cash in the second quarter of 2017. The2021, the Company currently expects to settle the remainder of the redetermination costs in future periods. It is possible that the final adjustment amount could be different than the current estimate. Due to the change inacquired an additional 3.5% working interest the future payments under a capital lease of a floating, production and storage facility in the KakapLucius field are lower and the Company reduced the total debt recorded on the Consolidated Balance Sheet in the second quarter 2017 by approximately $56.7for a purchase price of $22.5 million, with a similar reduction to Property, plant and equipment.Note CE – Discontinued Operations and Assets Held for SaleThe Company has accounted for its former 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, 20172022 and 20162021 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) 2022 2021 2022 2021 Revenues $ — 144 $ 10 801 Costs and expenses Other costs and expenses 422 850 1,926 1,401 Loss before taxes (422) (706) (1,916) (600) Income tax expense — — — — Loss from discontinued operations $ (422) (706) $ (1,916) (600) Certain reclassifications have been madeIn September 2022, the Company sold its share of Brunei block CA-2 to 2016 Revenues to align with current period presentationPetronas Carigali Brunei Ltd (see Note A)D for additional information).following table presentsremaining balance of assets held for sale on the Consolidated Balance Sheet as of September 30, 2022 consists only of the Company’s former headquarters office building in El Dorado, Arkansas. As of December 31, 2021, assets held for sale includes the carrying value of the major categoriesnet property, plant and equipment of assetsthe CA-2 project in Brunei, and liabilities of U.K. refining and marketing operations and Seal operationsthe Company’s former headquarters office building in Canada reflected as held for sale on the company’s Consolidated Balance Sheets at September 30, 2017 and December 31, 2016.(Thousands of dollars) September 30,
2022December 31,
2021Current assets Property, plant, and equipment, net 7,538 15,453 Total current assets associated with assets held for sale $ 7,538 15,453 17,030 4,126 6,218 22,944 23,248 27,070 605 270 2,665 2,506 3,270 2,776 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, 2022, 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, 2017,2022, the Company had no outstanding borrowings under the 2016 facility, however, there were $84.8RCF and $53.9 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. AdvancesRCF. At September 30, 2022, 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 4.84%. At September 30, 2017,2022 and 2021, the Company was in compliance with all covenants related to the 2016 facility.In September 2022, the Company paid $5.5 million to complete an open market repurchase of $7.1 million aggregate principal amount of its 6.125% senior notes due 2042 (2042 Notes). There were no additional cash costs related to the September 2022 debt extinguishment on the 2042 Notes for the three months and nine months ended September 30, 2022.In August 2022, the Company redeemed the remaining $42.4 million of its 6.875% senior notes due in 2024 (2024 Notes) and tendered $100.0 million and $98.1 million aggregate principal amount of its 5.750% and 6.375% senior notes due 2025 and 2028 (2025 Notes and 2028 Notes), respectively. The total cost of the debt extinguishment of $4.0 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months and nine months ended September 30, 2022. The debt extinguishment on the 2025 and 2028 Notes had cash costs of $2.0 million and is shown as a financing activity on the Consolidated Statement of Cash Flows for the three months and nine months ended September 30, 2022.In June 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% 2024 Notes. The cost of the debt extinguishment of $4.3 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2022. The cash costs of $3.4 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2022.12NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note F – Financing Arrangements and Debt (Contd.)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 $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; collectively 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 (SEC) that permits the offer and sale of debt and/or equity securities through October 2018.In August 2017,15, 2024.On October 31, 2022, the Company sold $550issued a notice of partial redemption with respect to $200.0 million aggregate principal amount of new notes that bear interestits 5.750% 2025 Notes. The Company will redeem the 2025 Notes at the rateapplicable redemption price set forth in the indenture governing the 2025 Notes, plus accrued and unpaid interest, if any, to, but not including, 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 payment2025 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 SeptemberNovember 30, 2017.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note 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) 2022 2021 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable ¹ $ (130,792) 75,100 (Increase) decrease in inventories (410) 9,718 (Increase) in prepaid expenses (8,561) (6,682) Increase in accounts payable and accrued liabilities ¹ 61,139 40,687 Increase (decrease) in income taxes payable 18,750 (1,493) Net (increase) decrease in noncash operating working capital $ (59,874) 117,330 Supplementary disclosures: Cash income taxes paid, net of refunds $ 16,493 1,685 Interest paid, net of amounts capitalized of $13.2 million in 2022 and $11.6 million in 2021 112,332 127,793 Non-cash investing activities: Asset retirement costs capitalized 2$ 29,327 36,300 Decrease in capital expenditure accrual 34,853 31,301 *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, 20172022 and 2016.2021.Three Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) (Thousands of dollars) 2022 2021 2022 2021 Service cost Service cost $ 2,129 1,770 $ 292 328 Interest cost Interest cost 5,163 4,258 574 521 Expected return on plan assets Expected return on plan assets (7,999) (6,038) — — Amortization of prior service cost (credit) Amortization of prior service cost (credit) 582 155 (133) — Recognized actuarial loss (gain) Recognized actuarial loss (gain) 3,822 5,269 (77) (8) Net periodic benefit expense Net periodic benefit expense $ 3,697 5,414 $ 656 841 Nine Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2022 2021 2022 2021 2,037 2,610 427 674 Service cost $ 6,387 5,306 $ 876 981 7,261 5,913 966 1,109 Interest cost 15,545 12,844 1,722 1,563 (8,070) (6,626) Expected return on plan assets (24,091) (18,326) — — 259 323 (18) (21) Amortization of prior service cost (credit) 1,761 467 (399) — 2 3,610 3,617 38 Recognized actuarial loss (gain) Recognized actuarial loss (gain) 11,466 15,829 (232) (23) 5,097 5,837 1,375 1,802 Net periodic benefit expense $ 11,068 16,120 $ 1,967 2,521 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 CurtailmentThe components of net periodic benefit expense, forother than the nine months ended September 30, 2016, shownservice cost, are recorded in Other income (expense) in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarterConsolidated Statements of 2016.During the nine-month period ended September 30, 2017,2022, the Company made contributions of $24.0$30.7 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 20172022 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8$11.9 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 2012 Annual Incentive Plan (2012 Annual Plan)(AIP) 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 2012 Annual PlanAIP 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 and other stock-based incentives. The 20122020 Long-Term Plan expires in 2022.2030. A total of 8,700,000five million 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 the 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 the Plan.14NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note I – Incentive Plans(Contd.)During the first nine months of 2022, 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 1580,600 February 1, 2022 $ 47.37 Monte Carlo Performance Based RSUs 115,100 July 1, 2022 $ 37.77 Monte Carlo Time Based RSUs 2273,400 February 1, 2022 $ 32.12 Average Stock Price Time Based RSUs 25,000 July 1, 2022 $ 29.80 Average Stock Price Cash Settled RSUs 3674,300 February 1, 2022 $ 32.12 Average Stock Price 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 generally 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.The Company had an Employee2021 Stock Purchase Plan (ESPP) that permittedfor Non-Employee Directors (2021 NED Plan) permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.The Company shares during 2016currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were 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 2017,2022, the Committee granted stock optionsthe following awards to Non-Employee Directors:2021 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 173,092 February 2, 2022 $ 32.84 Closing Stock Price 1 Non-employee directors time-based RSURSUs are scheduled to vest in February 2017.2023.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) 2022 2021 28,264 35,948 Compensation charged against income before tax benefit Compensation charged against income before tax benefit $ 43,216 29,145 8,695 11,796 Related income tax benefit recognized in income 6,872 4,120 1115NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note HJ – Earnings perPer ShareNet lossincome (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the20172022 and 2016.2021. 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) 2022 2021 2022 2021 172,572,873 172,199,350 172,509,418 172,164,683 Basic method 155,446,201 154,439,313 155,220,945 154,239,440 Dilutive stock options and restricted stock units ¹ Dilutive stock options and restricted stock units ¹ 1,889,972 1,492,949 2,185,957 — 172,572,873 172,199,350 172,509,418 172,164,683 Diluted method 157,336,173 155,932,262 157,406,902 154,239,440 *1Due to a net lossesloss recognized by the Company for all periods presented,the nine-month period ended September 30, 2021, 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 The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.Three Months Ended September 30, Nine Months Ended
September 30,2022 2021 2022 2021 Antidilutive stock options excluded from diluted shares — 1,316,222 163,800 1,502,758 Weighted average price of these options $ — $ 34.42 $ 49.65 $ 34.97 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, 20172022 and 2016,2021, the Company’s effective income tax rates were as follows:2022 2021 Three months ended September 30, 21.7% 21.1% Nine months ended September 30, 21.2% 28.6% The effective tax ratesrate for most periods where earnings are generated, generally exceedthe three-month period ended September 30, 2022, was above the U.S. statutory tax rate of 35%21% primarily 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 duecurrently available. These impacts were partially offset by no tax applied to a lackthe pre-tax income 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 the tax effect of expensesincome generated in foreign jurisdictions not fully deductible from losses at the U.S. statutoryCanada, which has a higher tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by no tax applied to the U.S.pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.The effective tax rate for the nine-month period ended September 30, 20172022, was above the U.S. statutory tax rate of 35%21% primarily due to an estimated U.S.several factors, including: the effects of income generated in foreign tax charge for undistributed foreign earnings and Canadian foreign exchange losses. These impacts were partially offset by the U.S.jurisdictions, certain of which have income tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items. During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise. Note I – Income Taxes (Contd.)The effective tax rate for the three-month period ended September 30, 2016 was lessrates higher than the U.S. statutoryFederal rate; U.S. state tax rate primarily due toexpense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were recognized. mostly offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.The effective tax rate for the nine-month period ended September 30, 20162021, was above the U.S. statutory tax rate of 21% primarily due to deferredno tax benefits recognized relatedapplied to the Canadian asset dispositions andpretax income of the noncontrolling interest in MP GOM, which has the impact of increasing the effective tax benefitsrate on investments in foreign areas. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains16or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of September 30, 2017,2022, 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; and Malaysia – 2010;2014. Following the sale in 2019, the Company has retained certain possible liabilities and United Kingdom – 2015.Note JL – Financial Instruments and Risk ManagementMurphy often uses derivative instruments, such as swap 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 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 until the anticipated transactions occur. This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.Commodity Purchase Price RisksThe Company is subject to commodity price risk related to crude oil it produces and sells. During the first nine months 2017 and 2016, the Company had West Texas Intermediate (WTI)has entered into crude oil swap financial contracts to economically hedge a portion of its United States production.and collar contracts. Under thesethe swaps 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 barrels2022, 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, 2016.122022 NYMEX WTI swap contracts: Volume per day (Bbl): 20,000 Price per Bbl: $ 44.88 NYMEX WTI collar contracts: Volume per day (Bbl): 25,000 Price per Bbl: Average Ceiling: $ 75.20 Average Floor: $ 63.24 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, 20172022 and December 31, 2016,2021, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.(Thousands of dollars) Asset (Liability) Derivatives Fair Value Type of Derivative Contract Balance Sheet Location September 30, 2022 December 31, 2021 (3,226) (48,864) (73) Commodity swaps Commodity swaps Accounts payable $ (84,933) (239,882) Commodity collars Commodity collars Accounts payable (20,954) (19,533) Commodity collars Commodity collars Accounts receivable — 4,280 17NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note L – Financial Instruments and Risk Management(Contd.)For the three-month and nine-month periods ended September 30, 20172022 and 2016,2021, 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.(13,573) 11,871 50,365 (22,678) 143 73 26,929 (13,573) 12,014 50,438 4,251 Gain (Loss) Gain (Loss) (Thousands of dollars) Statement of Operations Location Three Months Ended September 30, Nine Months Ended September 30, Type of Derivative
Contract2022 2021 2022 2021 Commodity swaps Gain (Loss) on derivative instruments $ 50,089 (43,235) $ (152,822) (483,865) Commodity collars Gain (Loss) on derivative instruments 65,102 (15,929) (155,832) (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, 20172022 and December 31, 20162021, 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, 2022 December 31, 2021 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity collars $ — — — — — 4,280 — 4,280 $ — — — — — 4,280 — 4,280 Liabilities: Commodity swaps $ — 84,933 — 84,933 — 239,882 — 239,882 Commodity collars — 20,954 — 20,954 — 19,533 — 19,533 Contingent consideration — — 212,860 212,860 — — 196,151 196,151 Nonqualified employee savings plan 15,642 — — 15,642 16,962 — — 16,962 $ 15,642 105,887 212,860 334,389 16,962 259,415 196,151 472,528 The fair value of WTIcommodity (WTI crude oil derivative contracts in 2017 and 2016oil) swaps was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in each yearcommodity (WTI crude oil) collars was based on market quotes for similar contracts at the balance sheet dates.determined using an option pricing model. The before 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, whileOperations. The contingent consideration, related to 2018 and 2019 U.S. Gulf of Mexico acquisitions, is valued using a Monte Carlo simulation model. For the effectsnine months ended September 30, 2022 and 2021, the pre-tax income effect of changes in the fair value of foreign exchange derivative contractsthe contingent consideration was an expense of $98.5 million and $105.1 million respectively and is recorded in Interest and other income. Other operating (income) expense in the Consolidated Statements of Operations. In the nine months ended September 30, 2022, the pre-tax income effect of changes in the fair value of the contingent consideration exclude cash payments of $81.7 million, which reduced the value of the contingent consideration liability. Contingent consideration is payable annually in years 2022 to 2026.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 pre-tax 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 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, 20172022 and December 31, 2016.2021.14NOTES 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, 20162021 and September 30, 20172022 and the changes during the nine-month period ended September 30, 20172022, 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
AdjustmentsTotal Balance at December 31, 2021 $ (311,895) (215,816) (527,711) Components of other comprehensive income (loss): Before reclassifications to income and retained earnings (135,791) — (135,791) Reclassifications to income — 9,674 ¹ 9,674 Net other comprehensive income (loss) (135,791) 9,674 (126,117) Balance at September 30, 2022 $ (447,686) (206,142) (653,828) 1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017$12,293 are included in the computation of net periodic benefit expense.expense for the nine-month period ended September 30, 2022. See Note GH for additional information. Related income taxes of $3,873$2,619 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 for the nine-month period ended September 30, 2017 are included in Interest expense, net. Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.Note LN – 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. GovernmentalGiven the factors involved in various government actions, are often motivated byincluding political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments. Itit is not practical to attemptdifficult to predict thetheir likelihood, of such actions, the form the actionsthey may take, or the effect such actionsthey 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 and safety 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 environment 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.There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and greenhouse gas emissions (including methane emissions). For example, the Inflation Reduction Act of 2022 contains provisions that impose fees for excess methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces,19NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note N– Environmental and Other Contingencies (Contd.)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. Executive orders have also been issued 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, the U.S. has since rejoined 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 commodity price derivatives), interest expense and unallocated overhead, is shown in the tablestable 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, 2022 Three Months Ended September 30, 2022 Three Months Ended September 30, 2021 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States $ 6,901.0 973.8 481.5 565.2 168.1 Canada 2,076.0 209.6 41.4 124.6 73.9 Other 237.4 4.8 (5.8) — (5.2) Total exploration and production 9,214.4 1,188.2 517.1 689.8 236.8 Corporate 1,014.0 115.2 57.4 (59.1) (98.8) Continuing operations 10,228.4 1,303.4 574.5 630.7 138.0 Discontinued operations, net of tax 0.8 — (0.4) — (0.7) Total $ 10,229.2 1,303.4 574.1 630.7 137.3 Nine Months Ended September 30, 2022 Nine Months Ended September 30, 2021 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ United States $ 2,659.2 1,225.9 1,704.4 481.8 Canada 582.3 111.3 349.2 (37.7) Other 18.5 (53.5) — (22.5) Total exploration and production 3,260.0 1,283.7 2,053.6 421.6 Corporate (302.6) (363.7) (493.3) (577.6) Continuing operations 2,957.4 920.0 1,560.3 (156.0) Discontinued operations, net of tax — (1.9) — (0.6) Total $ 2,957.4 918.1 1,560.3 (156.6) 1Additional details about results of oil and natural gas operations are presented in the tables on pages 29page 25 and 30.Note O – New Accounting Principles AdoptedBusiness Combinations21SummaryIn January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.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 changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Compensation – Retirement BenefitsIn March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Revenue from Contracts with CustomersIn May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the firstthird 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.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 relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.During the three-month and nine-month periods ended September 30, 2017, worldwide benchmark2022, crude oil and natural gas prices were above average comparable benchmark prices during 2016. Although pricesincreased compared to the same period of 2021. 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.Similar to the overall inflation in the wider economy, the oil and gas industry, and hence the Company, is observing higher costs for goods and services used in exploration and production operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs.For the three months ended September 30, 2017,2022, West Texas Intermediate (WTI) crude oil prices averaged approximately $91.55 per barrel (compared to $108.41 in the second quarter of 2022 and $70.56 in the third quarter of 2021). The average price for WTI in September of 2022 was approximately $83.80 per barrel, reflecting a 17% increase from September of 2021 and a 27% reduction from the average price from June of 2022. The average price in October 2022 was $87.03 per barrel. As of close on November 1, 2022, the NYMEX WTI forward curve prices for the remainder of 2022 and 2023 were $88.37 and $81.53 per barrel, respectively.For the three months ended September 30, 2022, the Company produced 154196 thousand barrels of oil equivalent per day. There was no production in the 2017 quarterday (including noncontrolling interest) from Canadian syntheticcontinuing operations and heavy oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively. The Company invested $287$296.1 million in capital expenditureexpenditures (on a value of work done basis), which included $79.1 million in acquisition capital, primarily for an additional working interests in the third quarter of 2017 primarily in the United States and Canada.GOM Lucius field. The Company reported a net lossincome from continuing operations of $65.9$574.5 million for the three months ended September 30, 2017, which included a foreign exchange2022; this amount includes income attributable to noncontrolling interest of $45.6 million and after-tax lossgains on unrealized mark to market revaluations on commodity price swap and collar positions and contingent consideration of $43.9$188.8 million principally on intercompany loans in the quarter and an after-tax loss of $11.8$24.8 million, inrespectively.In the third quarter relating to crude oil derivative contracts.In August 2022, the Company acquired an additional 3.37% working interest (there is no noncontrolling interest) in the Lucius field in the Gulf of Mexico for a purchase price of $77.1 million.For the nine-month periodnine months ended September 30, 2017,2022, 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 162173 thousand barrels of oil equivalent per day for the nine-month 2017 period(including noncontrolling interest) from continuing operations and invested $702$918.0 million in capital expenditures principally(on a value of work done basis), which included $125.6 million related to acquisition capital and $25.3 million related to the Cutthroat exploration well in Brazil deferred from 2021. The Company reported net income from continuing operations of $920.0 million for the nine months ended September 30, 2022. This amount includes income attributable to noncontrolling interest of $152.4 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $109.5 million and after-tax losses on contingent consideration of $77.5 million.In the second quarter of 2022, the Company achieved first production from the at the Khaleesi, Mormont, Samurai field development project in the United States and Canada.Gulf of Mexico; with production flowing through the Murphy-operated King’s Quay floating production facility. In addition, the Company acquired an additional 11.0% working interest (with no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $48.5 million.In the second quarter of 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% 2024 Notes for the principal amount plus cash costs of $3.4 million.For the three months ended September 30, 2021, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 14.5 thousand barrels of oil equivalent per day (including NCI). The Company incurredinvested $110.5 million in capital expenditures (on a non-cash deferred tax expensevalue of work done basis), in the firstthree months ended September 31, 2021. The Company reported net income from continuing operations of $138.0 million for the third quarter of 2021. This amount included income attributable to noncontrolling interest of $28.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $44.1 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on contingent consideration of $22.4 million.22For the nine months ended September 30, 2021, the Company produced 170 thousand barrels of 2017oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of $65.2Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI). The Company invested $568.7 million in capital expenditures (on a value of work done basis) in the nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay floating production system (which was subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of $156.0 million for the nine months ended September 30, 2021. This amount included income attributable to noncontrolling interest of $85.5 million, after-tax impairment charges of $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 derivative positions and contingent consideration of foreign subsidiaries,$180.5 million and $83.0 million, respectively.In the majority of which was recorded in first quarter of 2017 and recorded2021, the Company’s subsidiary, Murphy Exploration & Production Company - USA, closed a foreign exchange after-tax losstransaction with ArcLight Capital Partners, LLC (ArcLight) for the sale 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) 2022 2021 2022 2021 33.6 25.0 276.6 (99.5) Exploration and production $ 517.1 236.8 $ 1,283.7 421.6 (99.9) (39.6) (302.8) (111.7) Corporate and other 57.4 (98.8) (363.7) (577.6) (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 574.5 138.0 920.0 (156.0) Discontinued operations ¹ Discontinued operations ¹ (0.4) (0.7) (1.9) (0.6) Net income (loss) including noncontrolling interest Net income (loss) including noncontrolling interest $ 574.1 137.3 $ 918.1 (156.6) 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) 2022 2021 2022 2021 Exploration and production United States $ 481.5 168.1 $ 1,225.9 481.8 Canada 41.4 73.9 111.3 (37.7) Other (5.8) (5.2) (53.5) (22.5) Total $ 517.1 236.8 $ 1,283.7 421.6 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 with23ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)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) 2022 2021 2022 2021 Net income (loss) attributable to Murphy (GAAP) $ 528.4 108.5 $ 765.6 (242.1) Income tax expense (benefit) 159.5 36.8 247.6 (62.5) Interest expense, net 37.4 46.9 116.1 178.4 Depreciation, depletion and amortization expense ¹ 207.7 182.8 552.5 588.4 EBITDA attributable to Murphy (Non-GAAP) 933.0 375.0 1,681.8 462.2 Mark-to-market (gain) loss on derivative instruments (239.1) (55.9) (138.7) 228.5 Mark-to-market (gain) loss on contingent consideration (31.4) 28.4 98.5 105.1 Foreign exchange gain (20.7) (2.8) (28.7) (1.5) Gain on sale of assets ¹ (15.2) — (15.2) — Accretion of asset retirement obligations ¹ 10.0 10.8 30.7 30.8 Discontinued operations loss 0.4 0.7 1.9 0.6 Impairment of assets — — — 171.3 Unutilized rig charges — 3.2 — 8.5 Asset retirement obligation gains — (71.8) — (71.8) Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 637.1 287.6 $ 1,630.3 933.7 Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 17,525 14,219 44,973 43,536 Adjusted EBITDA per barrel of oil equivalents sold $ 36.35 20.23 $ 36.25 21.45 1 Depreciation, depletion, and amortization expense, gain on sale of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).24ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2022 AND 2021(Millions of dollars) UnitedStates 1Canada Other Total Three Months Ended September 30, 2022 Oil and gas sales and other operating revenues $ 973.8 164.1 4.8 1,142.7 Sales of purchased natural gas — 45.5 — 45.5 Lease operating expenses 158.8 39.6 0.3 198.7 Severance and ad valorem taxes 14.9 0.3 — 15.2 Transportation, gathering and processing 38.5 16.9 — 55.4 Costs of purchased natural gas — 43.7 — 43.7 Depreciation, depletion and amortization 169.4 40.9 0.9 211.2 Accretion of asset retirement obligations 8.8 2.4 — 11.2 Exploration expenses Dry holes and previously suspended exploration costs 0.2 — 0.9 1.1 Geological and geophysical 1.1 0.1 0.4 1.6 Other exploration 1.5 — 2.6 4.1 2.8 0.1 3.9 6.8 Undeveloped lease amortization 2.0 0.1 0.6 2.7 Total exploration expenses 4.8 0.2 4.5 9.5 Selling and general expenses 2.6 5.2 2.0 9.8 Other (27.7) 3.7 0.6 (23.4) Results of operations before taxes 603.7 56.7 (3.5) 656.9 Income tax provisions 122.2 15.3 2.3 139.8 Results of operations (excluding Corporate segment) $ 481.5 41.4 (5.8) 517.1 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 39.1 (71.7) 2.0 (30.6) Results of operations before taxes 208.0 99.1 (6.0) 301.1 Income tax provisions 39.9 25.2 (0.8) 64.3 Results of operations (excluding Corporate segment) $ 168.1 73.9 (5.2) 236.8 1 Includes results attributable to a noncontrolling interest in MP GOM.25ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2022 AND 2021(Millions of dollars) United
States 1Canada Other Total Nine Months Ended September 30, 2022 Oil and gas sales and other operating revenues $ 2,659.0 450.2 18.5 3,127.7 Sales of purchased natural gas 0.2 132.1 — 132.3 Lease operating expenses 368.2 113.4 1.2 482.8 Severance and ad valorem taxes 46.4 1.0 — 47.4 Transportation, gathering and processing 100.0 52.2 — 152.2 Costs of purchased natural gas 0.2 125.1 — 125.3 Depreciation, depletion and amortization 449.6 110.7 4.4 564.7 Accretion of asset retirement obligations 27.3 7.3 0.1 34.7 Exploration expenses Dry holes and previously suspended exploration costs (0.5) — 35.7 35.2 Geological and geophysical 3.7 0.2 1.4 5.3 Other exploration 5.9 0.4 14.7 21.0 9.1 0.6 51.8 61.5 Undeveloped lease amortization 6.7 0.2 3.8 10.7 Total exploration expenses 15.8 0.8 55.6 72.2 Selling and general expenses 14.1 14.1 6.5 34.7 Other 110.4 6.5 1.0 117.9 Results of operations before taxes 1,527.2 151.2 (50.3) 1,628.1 Income tax provisions (benefits) 301.3 39.9 3.2 344.4 Results of operations (excluding Corporate segment) $ 1,225.9 111.3 (53.5) 1,283.7 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 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 1 Includes results attributable to a noncontrolling interest in MP GOM.26ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Exploration and ProductionThird quarter 2022 vs. 2021All amounts include amount attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM), unless otherwise noted.United States E&P operations reported earnings of $481.5 million in the third quarter of 2022 compared to income of $168.1 million in the third quarter of 2021. Results were $313.4 million favorable in the 2022 quarter compared to the 2021 period primarily due to higher revenues ($408.6 million), lower exploration expenses ($17.1 million) and other operating expense ($66.8 million), partially offset by higher lease operating expenses ($62.1 million), higher depreciation, depletion and amortization (DD&A, $22.4 million) and higher income tax expense ($82.3 million). Higher revenues were primarily due to higher commodity prices, higher production volumes from the Khaleesi and Mormont fields and lower weather related downtime. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Lower other operating expense is primarily due to favorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher lease operating expense is due to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher DD&A is a result of higher production volumes, partially offset by lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Higher income tax expense is a result of higher pre-tax profits.Canadian E&P operations reported earnings of $41.4 million in the third quarter 2022 compared to income of $73.9 million in the third quarter of 2021. Results were unfavorable $32.5 million compared to the 2021 period primarily due to a credit of $71.8 million reported in 2021 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 revenues from production ($39.5 million), partially offset by higher lease operating expenses ($6.2 million) and higher tax expense ($9.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas volumes at Tupper Montney. Higher lease operating expenses is primarily the result of higher volumes and related gas processing costs. Higher income tax expense is a result of higher pre-tax profits.Other international E&P operations reported a loss from continuing operations of $5.8 million in the third quarter of 2022 compared to a loss of $5.2 million in the third quarter of 2021. The result was $0.6 million unfavorable in the 2022 period versus 2021 primarily due to higher exploration expenses and higher taxes partially offset by higher revenue from Brunei.Nine months 2022 vs. 2021All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.United States E&P operations reported earnings of $1,225.9 million in the first nine months of 2022 compared to earnings of $481.8 million in the first nine months of 2021. Results were $744.1 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($954.6 million) and lower DD&A ($27.0 million), other operating expense ($23.1 million) and exploration expenses ($16.9 million) partially offset by higher income tax expense ($188.4 million), lease operating expenses ($64.9 million) and severance and ad valorem taxes ($15.8 million). Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021. Lower DD&A is a result of lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Lower other operating expenses is primarily due to a lower unfavorable mark to market revaluation on contingent consideration ($98.5 million; as a result of commodity prices increasing less drastically) from prior GOM acquisitions and no repeat of rig standby charges. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Higher income tax expense is a result of higher pre-tax income. Higher lease operating expenses relate to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale.Canadian E&P operations reported earnings of $111.3 million in the first nine months of 2022 compared to a loss of $37.7 million in the first nine months of 2021. Results were $149.0 million favorable compared to the 2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter following an asset abandonment notice from the operator of 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 from production ($101.0 million) and lower DD&A ($17.3 million) offset by higher income tax expense ($52.7 million) and lease operating expenses ($13.4 million). Higher revenue is primarily attributable to higher realized prices and higher gas volumes (new wells added in 2022). Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay due to normal well decline.27ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses are due to higher gas volumes and higher processing rates.Other international E&P operations reported a loss of $53.5 million in the first nine months of 2022 compared to a loss of $22.5 million in the prior year. Results were $31.0 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.CorporateThird quarter 2022 vs. 2021Corporate 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 income of $57.4 million in the third quarter of 2022 compared to a loss of $98.8 million in the third quarter of 2021. The $156.2 million favorable variance is principally due to current period gains on derivative instruments in the third quarter of 2022 compared to losses in the same 2021 period (2022: $115.2 million gain; 2021: $59.2 million loss) for a favorable variance of $174.4 million. In addition, favorable variances were recorded due to lower interest expense ($10.9 million) and favorable exchange rate gains ($18.3 million) partially offset by higher tax expense ($47.1 million). Realized and unrealized gains on derivative instruments are due to a decrease in oil prices for current (realized) and/or future (unrealized) 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, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Interest charges are lower in the third quarter of 2022 due to lower overall debt in the period. Higher income tax expense is a result of higher pre-tax gains.Nine months 2022 vs. 2021Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $363.7 million in the first nine months of 2022 compared to a loss of $577.6 million in the first nine months of 2021. The $213.9 million favorable variance is primarily due to lower losses on derivative instruments in 2022 ($191.1 million) compared to 2021 (2022: $308.7 million loss; 2021: $499.8 million loss), lower interest expense ($62.4 million) and foreign exchange gains ($31.0 million), partially offset by lower tax benefits ($66.6 million). Interest charges are lower in the first nine months of 2022primarily due to lower overall debt and lower debt redemption premiums ($5.4 million in 2022; $36.8 million in 2021) incurred by the Company in the period. In the first nine months of 2022 the Company reduced debt by $447.6 million compared to the 2021 reduction of $726.4 million. Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) 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, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Lower income tax benefit is a result of lower pre-tax losses.Production Volumes and PricesThird quarter 2022 vs. 2021Total hydrocarbon production from continuing operations averaged 196,243 barrels of oil equivalent per day in the third quarter of 2022, which was 20% higher than the 163,224 barrels per day produced in third quarter 2021. The increase in production is principally due to production from the Khaleesi, Mormont and Samurai field development project that started production in the second quarter of 2022, new well production at Tupper Montney and lower weather related downtime in the third quarter of 2022.Average crude oil and condensate production from continuing operations was 103,386 barrels per day in the third quarter of 2022 compared to 88,245 barrels per day in the third quarter of 2021. The increase of 15,141 barrels per day was associated with higher volumes in the Gulf of Mexico (15,304 barrels per day) principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. Canada production is lower (2,680 barrels per day) primarily attributable to Kaybob Duvernay well decline and planned downtime at Hibernia. Eagle Ford Shale production is higher (2,329 barrels per day) due to new wells at Karnes and Catarina. On a worldwide basis, the Company’s crude oil and condensate prices averaged $93.56 per barrel in the third quarter 2022 compared to $68.88 per barrel in the 2021 period, an increase of 36% quarter over quarter.28ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)Total production of natural gas liquids (NGL) from continuing operations was 11,548 barrels per day in the third quarter 2022 compared to 10,391 barrels per day in the 2021 period. The increase of 1,157 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. The average sales price for U.S. NGL was $35.37 per barrel in the 2022 quarter compared to $32.01 per barrel in 2021. The average sales price for NGL in Canada was $54.40 per barrel in the 2022 quarter compared to $45.12 per barrel in 2021. 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 487.9 million cubic feet per day (MMCFD) in the third quarter 2022 compared to 387.5 MMCFD in 2021. The increase of 100.3 MMCFD was a result of higher volumes in Canada (82.8 MMCFD) as well as higher volumes in the Gulf of Mexico (19.0 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 20 new wells at Tupper Montney since the second quarter of 2022.Natural gas prices for the total Company averaged $3.84 per thousand cubic feet (MCF) in the 2022 quarter, versus $2.78 per MCF average in the same quarter of 2021. Average natural gas prices in the U.S. and Canada in the quarter were $8.34 and $2.75 per MCF, respectively. Average natural gas prices in Canada are lower as a result of certain fixed price sales volume contracts.Nine months 2022 vs. 2021Total hydrocarbon production from Exploration and Production averaged 173,260 barrels of oil equivalent per day in the first nine months of 2022, which represented a 1.8% increase from the 170,209 barrels per day produced in the first nine months of 2021. The increase is principally due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, new wells at Tupper Montney and lower weather related downtime in 2022.Average crude oil and condensate production was 95,275 barrels per day in the first nine months of 2022 compared to 98,314 barrels per day in the first nine months of 2021. The decrease of 3,039 barrels per day was principally due to normal declines partially offset by new production from the Khaleesi, Mormont, Samurai field development project. In addition, Canada production is lower (2,517 barrels per day) due to normal field decline at Kaybob and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (1,470 barrels per day) due to normal well decline partially offset by 2022 new well production. Higher Gulf of Mexico production (475 barrels per day) due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, and lower weather related downtime in 2022 partially offset by normal declines. On a worldwide basis, the Company’s crude oil and condensate prices averaged $99.38 per barrel in the first nine months of 2022 compared to $64.19 per barrel in the 2021 period, an increase of 54.8% year over year.Total production of natural gas liquids (NGL) was 10,621 barrels per day in the first nine months of 2022 compared to 10,498 barrels per day in the 2021 period. The average sales price for U.S. NGL was $38.30 per barrel in 2022 compared to $25.63 per barrel in 2021. The average sales price for NGL in Canada was $57.53 per barrel in 2022 compared to $37.05 per barrel in 2021. 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 averaged 404.2 million cubic feet per day (MMCFD) in the first nine months of 2022 compared to 368.4 MMCFD in 2021. The increase of 35.8 MMCFD was primarily the result of higher volumes in Canada 36.3 MMCFD) and Eagle Ford Shale (1.3 MMCFD), partially offset by the Gulf of Mexico (1.8 MMCFD). The higher natural gas volumes in Canada was the result of new wells on production in the nine months of the year. Natural gas prices for the total Company averaged $3.66 per thousand cubic feet (MCF) in the first nine months of 2022, versus $2.56 per MCF average in the same period of 2021. Average realized natural gas prices in the U.S. and Canada in the quarter were $7.00 per MCF and $2.70 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.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 reports hydrocarbons produced during the three-month and nine-month periods ended September 30, 2022 and 2021.Three Months Ended
September 30,Nine Months Ended
September 30,Barrels per day unless otherwise noted 2022 2021 2022 2021 Net crude oil and condensate United States Onshore 28,522 26,193 25,082 26,552 Gulf of Mexico 168,315 53,011 62,380 61,905 Canada Onshore 3,891 4,963 4,228 5,598 Offshore 2,171 3,779 2,869 4,016 Other 487 299 716 243 Total net crude oil and condensate - continuing operations 103,386 88,245 95,275 98,314 Net natural gas liquids United States Onshore 5,782 5,847 5,268 5,043 Gulf of Mexico 14,780 3,459 4,411 4,296 Canada Onshore 986 1,085 942 1,159 Total net natural gas liquids - continuing operations 11,548 10,391 10,621 10,498 Net natural gas – thousands of cubic feet per day United States Onshore 30,054 31,478 29,032 27,750 Gulf of Mexico 165,319 46,339 61,727 63,557 Canada Onshore 392,483 309,709 313,422 277,077 Total net natural gas - continuing operations 487,856 387,526 404,181 368,384 Total net hydrocarbons - continuing operations including NCI 2,3196,243 163,224 173,260 170,209 Noncontrolling interest Net crude oil and condensate – barrels per day (7,125) (7,546) (7,735) (8,834) Net natural gas liquids – barrels per day (264) (243) (290) (322) Net natural gas – thousands of cubic feet per day 2(2,202) (2,331) (2,628) (3,498) Total noncontrolling interest (7,756) (8,178) (8,463) (9,739) Total net hydrocarbons - continuing operations excluding NCI 2,3188,487 155,046 164,797 160,470 1 Includes net volumes attributable to a noncontrolling interest in MP GOM.2 Natural gas converted on an energy equivalent basis of 6:13 NCI – noncontrolling interest in MP GOM.30ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)Results of Operations (contd.)The following table reports the weighted average sales prices excluding transportation cost deductions and sales of purchased natural gas for the three-month and nine-month periods ended September 30, 20172022 and 20162021.Three Months Ended
September 30,Nine Months Ended
September 30,2022 2021 2022 2021 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore $ 94.33 69.30 $ 99.92 64.16 Gulf of Mexico 192.96 68.93 99.04 64.44 Canada 2Onshore 82.25 63.76 92.31 58.70 Offshore 111.76 72.64 112.93 68.93 Other 117.18 — 92.91 — Natural gas liquids – dollars per barrel United States Onshore 34.33 30.37 36.83 24.29 Gulf of Mexico 136.56 34.71 39.99 27.17 Canada 2Onshore 54.40 45.12 57.53 37.05 Natural gas – dollars per thousand cubic feet United States Onshore 7.62 3.85 6.49 3.23 Gulf of Mexico 18.68 4.09 7.23 3.28 Canada 2Onshore 2.75 2.47 2.70 2.33 1Prices include the effect of noncontrolling interest share for MP GOM.2 U.S. dollar equivalent.Financial ConditionThe Company’s primary sources of liquidity are reflected incash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. See below for additional discussion and analysis of the following table.Company’s cash flows.(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 ConditionNet cash provided by continuing operating activities was $819.6$1,678.7 million for the first nine months of 20172022 compared to $280.3$1,091.3 million during the same period in 2016.2021. The improvement inincreased cash provided by continuing operationsfrom operating activities in 2017 wasof $587.4 million is primarily attributable to higher realized sales prices for the Company’s oil and gasrevenue from production lower lease operating and administrative expenses, and rig cancellation payments in 2016 which are discussed below, partially($1,062.8 million), offset by lower volume sold in the current year and higher interest costs. Changes in operatingtiming of working capital from continuing operations increasedsettlements ($177.2 million; primarily higher revenue received in cash following the end of the quarter), offset by $1.1higher realized losses on derivative instruments ($176.1 million).Cash Required by Investing ActivitiesNet cash required by investing activities was $928.6 million duringfor the first nine months of 2017,2022 compared to a use$311.9 million during the same period in 2021. In the first nine months of cash of $152.62022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $48.5 million in 2016. The use of cash in 2016 included $266.6and $77.1 million, associated with pay-off of cancelled deepwater rig contracts thatrespectively (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which include amounts expensed, were previously charged to expense in 2015. Proceeds from sales of property$800.9 million 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$541.3 million in the 2017 periodfirst nine months of 2022 and $712.92021, respectively. The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $267.7 million, in 2016 from maturitywhich was sold to ArcLight.3127MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.(contd.)Financial Condition (Contd.(contd.)Cash used for property additions and dry holes, which includes amounts expensed, were $706.4 million and $781.7 million in the nine-month period ended September 30, 2017 and 2016, respectively. Total cash dividends to shareholders amounted to $129.4 million for the nine-months ended September 30, 2017 compared to $163.6 million in the same period of 2016 as the Company lowered the dividend from $1.40 per share to $1.00 per share effective in the third quarter 2016. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $651.2 million in the 2016 period. The proceeds of the $550 million notes issued in August 2017, were used to redeem the Company’s $550 million 2.50% notes in September 2017. The 2.50% notes had a maturity date of December 2017 and were retired early. The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 using proceeds from the sale of assets.Total accrual basis capital expenditures were as follows:are shown below.Nine Months Ended
September 30,(Millions of dollars) 2022 2021 Capital Expenditures 694.7 614.6 Exploration and production $ 904.1 556.0 6.9 20.7 Corporate 13.9 12.7 701.6 635.3 Total capital expenditures $ 918.0 568.7 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) 2022 2021 706.4 781.7 Property additions and dry hole costs per cash flow statements 1Property additions and dry hole costs per cash flow statements 1$ 800.9 541.3 Property additions King's Quay per cash flow statements Property additions King's Quay per cash flow statements — 17.7 Acquisition of oil and gas properties 1Acquisition of oil and gas properties 1125.6 22.9 37.7 32.8 Geophysical and other exploration expenses 20.4 13.3 (42.5) (179.2) Capital expenditure accrual changes and other (28.9) (26.6) 701.6 635.3 Total capital expenditures $ 918.0 568.7 1 Certain prior-period amounts have been reclassified to conform to the current period presentationThe increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Kodiak and Lucius acquisition in Gulf of Mexico ($125.6 million), Cutthroat-1 exploration well in Brazil ($25.3 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in Gulf of Mexico, higher development drilling activities in Eagle Ford Shale and Tupper Montney assets and higher expenditures related to the asset life extension at Terra Nova.Cash Required by Financing ActivitiesNet cash required by financing activities was $785.6 million for the first nine months of 2022 compared to $585.6 million during the same period in 2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024, 2025, 2028 and 2042 ($446.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($145.3 million), and cash dividends to shareholders of $0.575 per share ($89.4 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.25 per share, or $1.00 per share on an annualized basis.As of September 30, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,546.1 million available on its committed RCF.In first nine months of 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).Working CapitalWorking capital (total current assets less total current liabilities) atliabilities, excluding assets and liabilities held for sale) as of September 30, 20172022 was $615.6a deficit of $268.5 million, $558.8$30.4 million morelower than December 31, 2016,2021, with the increasedecrease primarily attributable to the Company redeeming the $550 million in 2.50% notes in September 2017, higher cash balancesaccounts receivable ($127.0 million) and lower accounts payable.32remainder of 2022 partially offset by higher revenue payables principally due to higher crude oil and gas pricing. Higher other accrued liabilities are associated with higher short term contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices and timing of payments. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project.Capital EmployedAt September 30, 2017,2022, long-term debt of $2,908.3$2,023.0 million had increaseddecreased by $485.5$442.4 million compared to December 31, 2016. 2021, primarily as a result of the partial repayment of notes due 2024, 2025, 2028 and 2042 ($447.6 million). The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.1%.A summary of capital employed at September 30, 20172022 and December 31, 20162021 follows.September 30, 2022 December 31, 2021 (Millions of dollars) Amount % Amount % Capital employed 2,908.3 36.9 2,422.8 33.0 Long-term debt $ 2,023.0 30.1 % $ 2,465.4 37.2 % 4,980.1 63.1 4,916.7 67.0 Murphy shareholders' equity Murphy shareholders' equity 4,708.9 69.9 % 4,157.3 62.8 % 7,888.4 100.0 7,339.5 100.0 Total capital employed $ 6,731.9 100.0 % $ 6,622.7 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. AtAs of September 30, 2017,2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5$95.3 million in Canada and $261.6 million in Malaysia.Canada. In addition, $17.0approximately $25.5 million of cash was held in Brunei, $20.9 million of cash was held in Mexico and $12.5 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.U.K.. 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)22, several factors have contributed to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.Compensation – Stock CompensationIn March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Compensation – Retirement BenefitsIn March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Revenue from Contracts with CustomersIn May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.Accounting and Other Matters (Contd.)LeasesIn February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.Statement of Cash FlowsIn August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.OutlookAverage worldwidelower average crude oil prices in October 2017 have slightly improved from the average pricesprice during the third quarter, which directly impacts the Company’s product revenue from sales (Q3 2022 $91.55; Q2 2022 $108.41; Q3 2021 $70.56). As of 2017. North American natural gasclose on November 1, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were lower at $88.37 and $81.53 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment, inflation and the Russia/Ukraine conflict) may have on future commodity prices. Lower prices decreased slightlywill result in October from the 2017 third quarter. The Company expects its total oillower profits 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 173.5 and 181.5 MBOEPD, excluding noncontrolling interest (NCI).The Company’s capital expenditure spend for 2022 is expected to be between $975.0 million and $1,025.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company currently anticipates total capital expenditures for the full year 2017plans to be approximately $940 million.The Company will primarily fund its remaining capital program in 20172022 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) in accordance with the Company’s capital allocation framework. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.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).33As of November 1, 2017,2022, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:Commodity Type Volumes
(Bbl/d)Price
(USD/Bbl)Remaining Period Area Start Date End Date United States WTI² Fixed price derivative swap 20,000 $44.88 10/1/2022 12/31/2022 Volumes
(Bbl/d)Average
Put
(USD/Bbl)Average
Call
(USD/Bbl)Remaining Period Area Commodity Type Start Date End Date United States WTI² Derivative collars 25,000 $63.24 $75.20 10/1/2022 12/31/2022 1 West Texas IntermediateContract orAverage
(MMcf/d)Price/Mcf Remaining Period CommoditiesLocationDatesVolumes per DayAverage PricesEnd Date U.S. OilWest Texas IntermediateOct. – Dec. 2017247 22,000 bbls/d$50.41 per bbl.10/1/2022 10/31/2022 U.S. OilWest Texas IntermediateJan. – Dec. 2018266 7,000 bbls/d$51.92 per bbl.11/1/2022 12/31/2022 Canada Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023 Natural Gas TCPL–NOVA SystemJul. – Dec. 2017124 mmcf/dC$2.97 per mcf12/31/2023 Natural Gas TCPL–NOVA SystemJan. – Dec. 201859 mmcf/dC$2.81 per mcf12/31/2024 Natural Gas Alberta AllianceNov. 2017 – Mar. 201820 mmcf/dUS$3.51 per mcf*12/31/2022 Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024 Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 *Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate.28ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)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 20162021 Annual Report on Form 10-K on file with the U.S. Securities and34ITEM 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, 20172022, covering certain future U.S. crude oil sales volumes in 2017.for the remainder of 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$28.5 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, 2017.2022.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, 2017,2022, 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 20162021 Form 10-K filed on February 24, 2017.25, 2022. The Company has not identified any additional risk factors not previously disclosed in its 20162021 Form 10-K report.The Exhibit Index on page 38 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/ CHRISTOPHERPAUL D. HULSEVAUGHANChristopherPaul 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