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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
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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 $ 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 Three Months Nine Months Ended September 30, Ended September 30, (Thousands of dollars) 2017 2016 2017 2016 Revenues (costs) $ Income (loss) before income taxes Income tax benefit – – – – Income (loss) from discontinued operations $ September 30, December 31, (Thousands of dollars) 2017 2016 Current assets Cash $ Accounts receivable Total current assets held for sale $ Current liabilities Accounts payable $ Refinery decommissioning cost Total current liabilities associated with assets held for sale $ Non-current liabilities Asset retirement obligation - Seal asset $ – RCF. 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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. six-month period ended June 30, 2023. Nine Months Ended September 30, (Thousands of dollars) 2017 2016 Compensation charged against income (loss) before tax benefit $ Related income tax benefit recognized in income three-month and Three Months Ended Nine Months Ended September 30, September 30, (Weighted-average shares) 2017 2016 2017 2016 Basic method Dilutive stock options and restricted stock units* – – – – Diluted method Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Antidilutive stock options excluded from diluted shares Weighted average price of these options $ $ $ $ 2017 2016 Three months ended September 30 (4.3%) 13.0% Nine months ended September 30 137.7% 48.9% noncontrolling interest in MP GOM. is currently available. 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 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 For the three-month and 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 – – – – – – $ – – 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 $ 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 In addition, 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 this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environment legal proceedings likely to exceed this $1.0 million threshold. 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 $ $2.95 and $3.45 per barrel, respectively. Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million. (Continued) 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 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 $ $46.5 million. 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 $ additional amounts being reclassified from long-term to current operating lease liabilities. September 30, 2017 December 31, 2016 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ % $ % Stockholders' equity % % Total capital employed $ % $ % any affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its Canada Exchange Commission (“SEC”) and on page 2023. By Vaughan 101. INS Inline XBRL Instance Document 101. SCH Inline XBRL Taxonomy Extension Schema Document 101. CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document 101. DEF Inline XBRL Taxonomy Extension Definition Linkbase Document 101. LAB Inline XBRL Taxonomy Extension Labels Linkbase Document 101. PRE Inline XBRL Taxonomy Extension Presentation LinkbaseSecurities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol Name of each exchange on which registered Common Stock, $1.00 Par Value MUR New York Stock Exchange Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.[X] ☒ Yes [ ]☐ NoIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).[X] ☒ Yes [ ]☐ No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”,filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]Emerging growth company [ ]Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). Emerging growth company [ ]Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.[ ]Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ NoNumber of shares of Common Stock, $1.00 par value, outstanding at OctoberJuly 31, 20172023 was 172,572,873.156,155,341.MURPHYMURPHY OIL CORPORATIONTABLE OF CONTENTS363636363636371MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED 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, except share amounts) June 30,
2023December 31,
2022ASSETS Current assets Cash and cash equivalents $ 369,355 $ 491,963 Accounts receivable, net 409,989 391,152 Inventories 62,450 54,513 Prepaid expenses 27,354 34,697 Total current assets 869,148 972,325 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,984,567 in 2023 and $12,489,970 in 2022 8,426,045 8,228,016 Operating lease assets 867,353 946,406 Deferred income taxes 40,678 117,889 Deferred charges and other assets 46,306 44,316 Total assets $ 10,249,530 $ 10,308,952 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 705 $ 687 Accounts payable 584,107 543,786 Income taxes payable 23,539 26,544 Other taxes payable 32,091 22,819 Operating lease liabilities 258,278 220,413 Other accrued liabilities 135,788 443,585 Total current liabilities 1,034,508 1,257,834 Long-term debt, including finance lease obligation 1,823,521 1,822,452 Asset retirement obligations 843,328 817,268 Deferred credits and other liabilities 299,089 304,948 Non-current operating lease liabilities 624,736 742,654 Deferred income taxes 235,665 214,903 Total liabilities $ 4,860,847 $ 5,160,059 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 2023 and 195,100,628 shares in 2022 195,101 195,101 Capital in excess of par value 861,951 893,578 Retained earnings 6,259,561 6,055,498 Accumulated other comprehensive loss (495,783) (534,686) Treasury stock (1,586,522) (1,614,717) Murphy Shareholders' Equity 5,234,308 4,994,774 Noncontrolling interest 154,375 154,119 Total equity 5,388,683 5,148,893 Total liabilities and equity $ 10,249,530 $ 10,308,952 2MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)(Thousands of dollars, except per share amounts)498,202 486,276 1,552,473 1,326,587 117 (730) 130,765 3,101 498,319 485,546 1,683,238 1,329,688 112,751 119,663 346,072 435,296 10,816 9,592 32,771 35,668 28,492 19,866 77,356 83,910 56,672 55,523 168,259 196,143 243,636 255,900 714,782 797,288 10,654 11,043 31,638 35,514 95,088 2,454 6,486 10,988 (1,446) 465,475 478,073 1,381,866 1,677,461 32,844 7,473 301,372 (347,773) (47,721) 14,987 (93,524) 38,602 (48,681) (39,219) (138,423) (103,889) (96,402) (24,232) (231,947) (65,287) (63,558) (16,759) 69,425 (413,060) 2,760 (2,176) 95,602 (201,897) (66,318) (14,583) (26,177) (211,163)
net of income taxes425 (1,593) 1,177 (885) (65,893) (16,176) (25,000) (212,048) (0.38) (0.08) (0.15) (1.23) (0.01) 0.01 (0.01) (0.38) (0.09) (0.14) (1.24) (0.38) (0.08) (0.15) (1.23) (0.01) 0.01 (0.01) (0.38) (0.09) (0.14) (1.24) 0.25 0.25 0.75 0.95 172,573 172,199 172,509 172,165 172,573 172,199 172,509 172,165 Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars, except per share amounts) 2023 2022 2023 2022 Revenues and other income Revenue from production $ 799,836 $ 1,146,299 $ 1,596,067 $ 1,980,827 Sales of purchased natural gas 13,014 49,939 56,751 86,785 Total revenue from sales to customers 812,850 1,196,238 1,652,818 2,067,612 Loss on derivative instruments – (103,068) – (423,845) Gain on sale of assets and other income 1,738 7,887 3,486 10,251 Total revenues and other income 814,588 1,101,057 1,656,304 1,654,018 Costs and expenses Lease operating expenses 194,292 147,352 394,276 284,177 Severance and ad valorem taxes 12,765 17,565 24,205 32,200 Transportation, gathering and processing 59,868 49,948 113,790 96,871 Costs of purchased natural gas 9,657 47,971 41,926 81,636 Exploration expenses, including undeveloped lease amortization 115,793 15,151 125,975 62,717 Selling and general expenses 25,345 27,130 43,653 60,659 Depreciation, depletion and amortization 215,667 195,856 411,337 359,980 Accretion of asset retirement obligations 11,364 11,563 22,521 23,439 Other operating expense 4,960 36,913 16,948 142,855 Total costs and expenses 649,711 549,449 1,194,631 1,144,534 Operating income from continuing operations 164,877 551,608 461,673 509,484 Other income (loss) Other (expenses) income (7,694) 5,308 (7,767) 2,813 Interest expense, net (29,856) (41,385) (58,711) (78,662) Total other loss (37,550) (36,077) (66,478) (75,849) Income from continuing operations before income taxes 127,327 515,531 395,195 433,635 Income tax expense 34,870 105,084 88,703 88,123 Income from continuing operations 92,457 410,447 306,492 345,512 Loss from discontinued operations, net of income taxes (602) (943) (323) (1,494) Net income including noncontrolling interest 91,855 409,504 306,169 344,018 Less: Net (loss) income attributable to noncontrolling interest (6,431) 58,947 16,239 106,797 NET INCOME ATTRIBUTABLE TO MURPHY $ 98,286 $ 350,557 $ 289,930 $ 237,221 INCOME PER COMMON SHARE – BASIC Continuing operations $ 0.63 2.27 $ 1.86 $ 1.54 Discontinued operations – (0.01) – (0.01) Net income $ 0.63 2.26 $ 1.86 $ 1.53 INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 0.62 $ 2.24 $ 1.84 $ 1.51 Discontinued operations – (0.01) – (0.01) Net income $ 0.62 $ 2.23 $ 1.84 $ 1.50 Cash dividends per common share $ 0.275 $ 0.175 $ 0.550 $ 0.325 Average common shares outstanding (thousands) Basic 156,127 155,389 155,976 155,121 Diluted 157,299 157,455 157,308 157,852 See Notes to Consolidated Financial Statements, page 7.*Reclassified to conform to current presentation (see Note A).3MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)(Thousands of dollars)(65,893) (16,176) (25,000) (212,048) 101,210 (37,369) 194,094 124,522 2,396 2,515 7,169 7,544
expense482 482 1,445 1,445 104,088 (34,372) 202,708 133,511 38,195 (50,548) 177,708 (78,537) Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2023 2022 2023 2022 Net income including noncontrolling interest $ 91,855 $ 409,504 $ 306,169 $ 344,018 Other comprehensive (loss) income, net of tax Net gain (loss) from foreign currency translation 33,083 (51,545) 36,752 (33,525) Retirement and postretirement benefit plans 1,053 3,173 2,151 6,509 Other comprehensive (loss) income 34,136 (48,372) 38,903 (27,016) Comprehensive income (loss) including noncontrolling interest $ 125,991 $ 361,132 $ 345,072 $ 317,002 Less: Comprehensive income attributable to noncontrolling interest (6,431) 58,947 16,239 106,797 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 132,422 $ 302,185 $ 328,833 $ 210,205 4MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED 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 12016 balance includes payments for deepwater rig contract exit of $266.6 million.2Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.3Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.Six Months Ended
June 30,(Thousands of dollars) 2023 2022 Operating Activities Net income including noncontrolling interest $ 306,169 $ 344,018 Adjustments to reconcile net income to net cash provided by continuing operations activities Loss from discontinued operations 323 1,494 Depreciation, depletion and amortization 411,337 359,980 Unsuccessful exploration well costs and previously suspended exploration costs 96,533 34,102 Amortization of undeveloped leases 5,369 7,980 Accretion of asset retirement obligations 22,521 23,439 Deferred income tax expense 92,557 66,691 Contingent consideration payment (139,574) – Mark to market loss on contingent consideration 7,113 129,818 Mark to market loss on derivative instruments – 100,343 Long-term non-cash compensation 22,076 40,467 Gain from sale of assets – (35) Net increase in noncash working capital (15,340) (121,598) Other operating activities, net (59,417) (27,458) Net cash provided by continuing operations activities 749,667 959,241 Investing Activities Property additions and dry hole costs (694,753) (552,825) Acquisition of oil and natural gas properties – (46,491) Proceeds from sales of property, plant and equipment – 47 Net cash required by investing activities (694,753) (599,269) Financing Activities Borrowings on revolving credit facility 200,000 100,000 Repayment of revolving credit facility (200,000) (100,000) Retirement of debt – (200,000) Early redemption of debt cost – (3,438) Distributions to noncontrolling interest (15,983) (94,854) Contingent consideration payment (60,243) (81,742) Cash dividends paid (85,867) (50,491) Withholding tax on stock-based incentive awards (14,220) (16,697) Capital lease obligation payments (296) (320) Issue costs of debt facility (20) – Net cash required by financing activities (176,629) (447,542) Effect of exchange rate changes on cash and cash equivalents (893) (1,595) Net decrease in cash and cash equivalents (122,608) (89,165) Cash and cash equivalents at beginning of period 491,963 521,184 Cash and cash equivalents at end of period $ 369,355 $ 432,019 5MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)(Thousands of dollars)
none issued
issued 195,055,724 shares at September 30, 2017 and 2016.195,056 195,056 195,056 195,056 916,799 910,074 (26,553) (10,078) 20,767 21,918 (77) (239) 910,936 921,675 5,729,596 6,212,201 (25,000) (212,048) (129,421) (163,586) 5,575,175 5,836,567 (628,212) (704,542) 194,094 124,522 7,169 7,544
net of income taxes1,445 1,445 (425,504) (571,031) (1,296,560) (1,306,061) 145 389 20,886 8,993
2017 and 22,855,649 shares of Common Stock in 2016, at cost(1,275,529) (1,296,679) 4,980,134 5,085,588 Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars except number of shares) 2023 2022 2023 2022 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 June 30, 2023 and 195,100,628 shares at June 30, 2022Balance at beginning and end of period 195,101 195,101 195,101 195,101 Capital in Excess of Par Value Balance at beginning of period 857,000 880,537 893,578 926,698 Restricted stock transactions and other (2,321) (3,415) (42,415) (55,804) Share-based compensation 7,272 6,246 10,788 12,474 Balance at end of period 861,951 883,368 861,951 883,368 Retained Earnings Balance at beginning of period 6,204,217 5,082,034 6,055,498 5,218,670 Net income attributable to Murphy 98,286 350,557 289,930 237,221 Cash dividends paid (42,942) (27,191) (85,867) (50,491) Balance at end of period 6,259,561 5,405,400 6,259,561 5,405,400 Accumulated Other Comprehensive Loss Balance at beginning of period (529,919) (506,355) (534,686) (527,711) Foreign currency translation (loss) gain, net of income taxes 33,083 (51,545) 36,752 (33,525) Retirement and postretirement benefit plans, net of income taxes 1,053 3,173 2,151 6,509 Balance at end of period (495,783) (554,727) (495,783) (554,727) Treasury Stock Balance at beginning of period (1,588,841) (1,618,478) (1,614,717) (1,655,447) Awarded restricted stock, net of forfeitures 2,319 2,138 28,195 39,107 Balance at end of period – 38,945,622 shares of Common Stock in 2023 and 39,677,584 shares of Common Stock in 2022, at cost (1,586,522) (1,616,340) (1,586,522) (1,616,340) Murphy Shareholders’ Equity 5,234,308 4,312,802 5,234,308 4,312,802 Noncontrolling Interest Balance at beginning of period 167,110 171,451 154,119 163,485 Net income attributable to noncontrolling interest (6,431) 58,947 16,239 106,797 Distributions to noncontrolling interest owners (6,304) (54,970) (15,983) (94,854) Balance at end of period 154,375 175,428 154,375 175,428 Total Equity $ 5,388,683 $ 4,488,230 $ 5,388,683 $ 4,488,230 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(U.S.) 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 June 30, 2023, our maximum exposure to loss was $3.1 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 SeptemberJune 30, 20172023 and December 31, 2016,2022, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended SeptemberJune 30, 20172023 and 2016,2022, in conformity with U.S generally accepted accounting principles generally accepted in the United States of America (U.S.)(GAAP). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S.,GAAP, management has made a number of estimates and assumptions related tothat affect the reporting of amounts 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 2022 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172023 are not necessarily indicative of future results.BeginningNote B – New Accounting Principles and Recent Accounting PronouncementsAccounting Principles AdoptedNone.Recent Accounting PronouncementsNone affecting the Company.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 period ended September 30, 2017, certain reclassificationsproduced 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 to7NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note C – Revenue from Contracts with Customers (Continued)this is the reporting of the noncontrolling interest in presentation have been madeMP Gulf of Mexico, LLC (MP GOM) as prescribed by ASC 810-10-45.U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the Consolidated Statementscustomer 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 Operations.vessel load, based on the volumes on the bill of lading and point of custody transfer. The Company now presents a separate “Operating income (loss)also purchases natural gas in Canada to meet certain sales commitments.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note C – Revenue from continuing operations” subtotalContracts with Customers (Continued)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 June 30, 2023, and 2022, the Company recognized $812.9 million and $1,196.2 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.For the six-month periods ended June 30, 2023, and 2022, the Company recognized $1,652.8 million and $2,067.6 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.Three Months Ended
June 30,Six Months Ended
June 30,(Thousands of dollars) 2023 2022 2023 2022 Net crude oil and condensate revenue United States Onshore $ 177,085 $ 264,841 $ 307,166 $ 436,537 Offshore 480,841 612,526 981,151 1,078,147 Canada Onshore 19,306 40,417 41,258 77,114 Offshore 24,871 38,354 41,001 67,186 Other – 13,636 3,644 13,636 Total crude oil and condensate revenue 702,103 969,774 1,374,220 1,672,620 Net natural gas liquids revenue United States Onshore 6,540 18,062 14,810 34,747 Offshore 11,541 18,093 26,170 32,072 Canada Onshore 1,517 5,001 4,980 9,868 Total natural gas liquids revenue 19,598 41,156 45,960 76,687 Net natural gas revenue United States Onshore 4,138 19,034 9,588 30,403 Offshore 14,802 43,567 36,934 69,768 Canada Onshore 59,195 72,768 129,365 131,349 Total natural gas revenue 78,135 135,369 175,887 231,520 Revenue from production 799,836 1,146,299 1,596,067 1,980,827 Sales of purchased natural gas United States Offshore – 181 – 181 Canada Onshore 13,014 49,758 56,751 86,604 Total sales of purchased natural gas 13,014 49,939 56,751 86,785 Total revenue from sales to customers 812,850 1,196,238 1,652,818 2,067,612 Loss on derivative instruments – (103,068) – (423,845) Gain on sale of assets and other income 1,738 7,887 3,486 10,251 Total revenues and other income $ 814,588 $ 1,101,057 $ 1,656,304 $ 1,654,018 Contract Balances and Asset RecognitionAs of June 30, 2023, and December 31, 2022, receivables from contracts with customers, net of royalties and associated payables, on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below Operating income (loss) from continuing operations. Previously reported periods have been changed to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss)balance sheets from continuing operations, before income taxes, Losswere $197.4 million and $201.1 million,9NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note C – Revenue from continuing operations,Contracts with Customers (Continued)respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or Net Loss.The Company has not entered into any revenue contracts that have financing components as of June 30, 2023.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 June 30, 2023, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:Current Long-Term Contracts Outstanding at June 30, 2023 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGL Q1 2030 Deliveries from dedicated acreage in Eagle Ford As produced 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 index fixed prices 15 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD index prices 28 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCFD Canada Natural Gas Q4 2027 Contracts to sell natural gas at CAD index prices 10 MMCFD Canada NGL Q3 2023 Contracts to sell natural gas liquids at CAD prices 952 BOEPD 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) guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.At September10NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note D – Property, Plant and Equipment (Continued)As of June 30, 2017,2023, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4$193.4 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-monthsix-month periods ended SeptemberJune 30, 20172023 and 2016.2022.(Thousands of dollars) 2023 2022 148,500 130,514 Beginning balance at January 1 $ 171,860 $ 179,481 51,614 847 Additions pending the determination of proved reserves 47,733 9,412 (13,370) (8,360) Capitalized exploratory well costs charged to expense (26,188) (10,472) (3,205) 178,384 128,156 Balance at June 30 Balance at June 30 $ 193,405 $ 178,421 Capital additions of $47.7 million in 2023 are primarily related to Oso #1 well (Atwater Valley 138) and Longclaw GC 433 #1 in the Gulf of Mexico and LDV-4X in Vietnam. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The capitalizedCompany plans to return to the well in the third quarter of 2023. Capitalized well costs charged to dry hole expense of $26.2 million for the six months ended June 30, 2023 are related to Cholula -1 EXP well in Mexico and Chinook #7 exploration well in the Gulf of Mexico. The preceding table excludes well costs of $70.3 million incurred and expensed directly to dry hole during the first ninesix months of 2017 includedended June 30, 2023, related to the Marakas-01Chinook #7 exploration well in Block SK314A, offshore Malaysia in which developmentthe Gulf of the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to commodity prices.Mexico.6NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note B – Property, Plant and Equipment (Contd.)June 30, 2023 2022 (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 $ 8,494 1 1 $ 4,268 2 2 8,430 2 2 53,101 3 3 One to two years 38,497 1 1 2,813 2 2 43,197 1 1 31,627 2 Two to three years 2,698 1 1 26,848 3 2 85,148 7 1 32,865 4 Three years or more 143,716 4 3 144,492 8 2 178,384 13 6 128,156 11 5 $ 193,405 7 6 $ 178,421 15 8 Of the $136.8$184.9 million of exploratory well costs capitalized more than one year at SeptemberJune 30, 2017, $70.42023, $112.4 million is in Brunei, $43.2 million iswas in Vietnam, $65.0 million was in the U.S., $4.8 million was in Canada, and $23.2$2.7 million iswas in Malaysia.Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. DivestmentsIn January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $132.4 million pretax gain was reported in the first quarter of 2017 related to the sale. Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately $19.4 million. ImpairmentsThere were no gainsimpairments in the six months ended June 30, 2023 or losses recorded related to these sales. During the second quarter 2016, a Canadian subsidiary of2022.DivestituresOn July 31, 2023 the Company completed theentered into a purchase and sale agreement to sell a portion of its five percent,our operated non-core Kaybob Duvernay assets and all of our non-operated working interestPlacid Montney assets, located in SyncrudeAlberta, Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”). The Company receivedfor net cash proceedsconsideration of $739.1 million and recorded an after-tax gain of $71.7 millionC$150 million. The transaction is anticipated to close in the nine-month period ended Septemberthird quarter of 2023, subject to closing conditions and adjustments. No gain or loss is anticipated in relation to this transaction. These assets did not meet the accounting criteria to be disclosed as held for sale as of June 30, 2016 associated with the Syncrude divestiture.During the second quarter 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing2023 and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. A gaincontinue to be classified as “Property, plant and equipment” on sale of approximately $187.0 million was deferred and is being recognized over the next 19 years in the Canadian operating segment. The Company amortized approximately $5.3 million and $3.4 million of the deferred gain during the nine-month periods ended September 30, 2017 and 2016, respectively. The remaining deferred gain of $185.0 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheet asSheets.Note E – Financing Arrangements and DebtAs of SeptemberJune 30, 2017.AcquisitionsDuring2023, the second quarter 2016,Company had an $800 million revolving credit facility (RCF). The RCF is a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities insenior unsecured guaranteed facility which expires on November 17, 2027, unless the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the termsoutstanding principal amount of the joint venture, the total consideration amounts to approximately $375.0Company’s 5.75% senior notes due 2025 (2025 Notes) as at February 15, 2025 exceeds $50.0 million, in117(Contd.)Note B – 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. The Company currently expects to settle the remainder of the redetermination costs in future periods. It is possible that the final adjustment amount could be different than the current estimate. Due to the change in working interest, the future payments under a capital lease of a floating, production and storage facility in the Kakap field are lower and the Company reduced the total debt recorded on the Consolidated Balance Sheet in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.Note C – Discontinued Operations and Assets Held for SaleThe Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2017 and 2016 were as follows:598 5 853 1,454 425 (1,593) 1,177 (885) 425 (1,593) 1,177 (885) Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations and Seal operations in Canada reflected as held for sale on the company’s Consolidated Balance Sheets at September 30, 2017 and December 31, 2016.17,030 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 DE – Financing Arrangements and DebtAt September (Continued)which case, the RCF will expire on that date. As of June 30, 2017,2023, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019.had $248.7 million outstanding on the 2025 Notes. At SeptemberJune 30, 2017,2023, the Company had no outstanding borrowings under the 2016 facility, however, there were $84.8RCF and $30.4 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. AdvancesRCF. At June 30, 2023, 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 rateRCF would have been 4.50%7.74%. At SeptemberJune 30, 2017,2023, the Company was in compliance with all covenants related to the 2016 facility.The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 2018.In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025. The Company incurred transaction costs of $8.2 million on the issue of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment will be paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 2.50% notes in September 2017. The 2.50% notes had an original maturity of December 2017.In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion), with a major banking consortium that expires in August 2019. The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows. Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024. The proceeds of the $550 million notes were used for general corporate purposes.The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through March 2029. Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.8 million and $136.5 million, respectively, associated with this lease at September 30, 2017.8NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note EF – Other Financial InformationAdditional disclosures regarding cash flow activities are provided below.
cash and cash equivalents:90,614 75,841 5,869 (15,768) 25,285 122,399 720 (115,977) (376,310) (4,721) 40,500 1,070 (152,618) 25,118 (3,911)
and $3,318 in 201695,899 52,287 38,992 13,959 42,403 179,203 Six Months Ended
June 30,(Thousands of dollars) 2023 2022 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) in accounts receivable $ (18,915) $ (263,104) (Increase) decrease in inventories (8,353) (10,092) (Increase) decrease in prepaid expenses 8,291 (1,693) Increase in accounts payable and accrued liabilities ¹ 6,642 147,790 Increase (decrease) in income taxes payable (3,005) 5,501 Net increase in noncash working capital $ (15,340) $ (121,598) Supplementary disclosures: Cash income taxes paid, net of refunds $ 10,904 $ 1,783 Interest paid, net of amounts capitalized of $6.8 million in 2023 and $10.4 million in 2022 54,305 78,747 Non-cash investing activities: Asset retirement costs capitalized $ 2,742 $ 9,007 (Increase) decrease in capital expenditure accrual 20,522 (1,929) *2016 balance included payments1 Excludes payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.Note G – Asset Retirement ObligationsThe asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.A reconciliation of the beginning and ending aggregate carrying amount of the ARO for deepwater rig contract exitthe six-month periods ended June 30, 2023 and 2022 is shown in the following table.129(Contd.)Note FG – Asset Retirement Obligations (Continued)(Thousands of dollars) June 30, 2023 June 30, 2022 Balance at beginning of year $ 911,653 971,893 Accretion 22,521 23,439 Liabilities incurred 4,805 9,007 Revisions of previous estimates (822) — Liabilities settled (64,978) (26,144) Changes due to translation of foreign currencies 2,920 (3,650) Balance at end of year 876,099 974,545 Current portion of liability at June 30 ¹ (32,771) (110,653) Noncurrent portion of liability at June 30 $ 843,328 863,892 1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.Note H – 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 onmeet the requirements of 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.13NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)The table that follows provides the components of net periodic benefit expense for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172023 and 2016.2022.Three Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2023 2022 2023 2022 2,037 2,610 427 674 Service cost $ 1,650 $ 2,129 $ 132 $ 292 7,261 5,913 966 1,109 Interest cost 8,564 5,139 874 574 (8,070) (6,626) Expected return on plan assets (8,254) (7,954) – – Estimated defined contribution provision Estimated defined contribution provision 54 – – – 259 323 (18) (21) Amortization of prior service cost (credit) 155 579 (133) (133) 2 3,610 3,617 38 5,097 5,837 1,375 1,802 Recognized actuarial loss (gain) Recognized actuarial loss (gain) 2,414 3,822 (767) (78) Total net periodic benefit expense Total net periodic benefit expense $ 4,583 3,715 106 655 Six Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2023 2022 2023 2022 6,099 8,533 1,276 2,022 Service cost $ 3,300 $ 4,258 $ 264 $ 584 20,267 20,386 2,899 3,324 Interest cost 17,071 10,382 1,748 1,148 (21,730) (21,709) Expected return on plan assets (16,448) (16,092) – – Estimated defined contribution provision Estimated defined contribution provision 108 — – – 767 963 (55) (62) Amortization of prior service cost (credit) 310 1,179 (266) (266) 4 10,673 10,864 113 822 (19) 16,076 19,859 4,120 5,382 Recognized actuarial loss (gain) Recognized actuarial loss (gain) 4,815 7,644 (1,548) (155) Total net periodic benefit expense Total net periodic benefit expense $ 9,156 $ 7,371 $ 198 $ 1,311 CurtailmentThe components of net periodic benefit expense, forother than the nine months ended September 30, 2016, shownservice cost, are recorded in “Other (expenses) income” 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-monthsix-month period ended SeptemberJune 30, 2017,2023, the Company made contributions of $24.0$18.9 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 20172023 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8$18.2 million.10NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note 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 been14NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note I – Incentive Plans (Continued)canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.During the six months ended June 30, 2023, 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 1409,160 January 31, 2023 $ 60.46 Monte Carlo Time Based RSUs 2499,220 January 31, 2023 43.27 Average Stock Price Cash Settled RSUs 3123,230 January 31, 2023 43.27 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 Employeecurrently has outstanding incentive awards issued to Directors under the 2021 Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016for Non-Employee Directors (2021 NED Plan) and the first2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.During the six months of 2017. The ESPP terminated onended June 30, 2017 and was not renewed by the Company.In February 2017,2023, 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 156,880 February 1, 2023 $ 42.20 Closing Stock Price 1 Non-employee directors time-based RSURSUs are scheduled to vest in February 2017.2024.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:Six Months Ended
June 30,(Thousands of dollars) 2023 2022 28,264 35,948 Compensation charged against income before tax benefit Compensation charged against income before tax benefit $ 23,684 $ 34,016 8,695 11,796 Related income tax benefit recognized in income 3,444 5,822 1115NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)(CONTINUED)Note HJ – Earnings perPer ShareNet lossincome attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for thenine-monthsix-month periods ended SeptemberJune 30, 20172023 and 2016.2022. The following table reconcilesreports the weighted-average shares outstanding used for these computations.172,572,873 172,199,350 172,509,418 172,164,683 172,572,873 172,199,350 172,509,418 172,164,683 *DueThree Months Ended
June 30,Six Months Ended
June 30,(Weighted-average shares) 2023 2022 2023 2022 Basic method 156,126,580 155,388,555 155,976,326 155,121,098 Dilutive stock options and restricted stock units ¹ 1,172,382 2,066,575 1,331,696 2,730,624 Diluted method 157,298,962 157,455,130 157,308,022 157,851,722 1 The following table reflects certain options to net losses recognized bypurchase shares of common stock that were outstanding during the Company for all periods presented no unvested stock awardsbut were not included in the computation of diluted earnings per shareshares above because the effect would have been anti-dilutive.incremental shares from the assumed conversion were antidilutive.Six Months Ended
June 30,2023 2022 5,257,718 5,884,201 5,578,495 5,822,036 Antidilutive stock options excluded from diluted shares $ – $ 234,000 46.46 49.00 46.86 49.82 Weighted average price of these options $ – $ 49.65 Note IK – Income TaxesThe Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income tax expense.taxes. For the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172023 and 2016,2022, the Company’s effective income tax rates were as follows:2023 2022 Three months ended June 30, 27.4% 20.4% Six months ended June 30, 22.4% 20.3% The effective tax ratesrate for most periods where earnings are generated, generally exceedthe three-month period ended June 30, 2023, was above the U.S. statutory tax rate of 35%21% primarily due to several factors, including: no tax benefit applied to the pre-tax loss of the noncontrolling interest in MP GOM; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.The effective tax rate for the three-month period ended June 30, 2022, was below the statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.The effective tax rate for the six-month period ended June 30, 2023 was above the U.S. statutory tax rate of 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-monthsix-month period ended SeptemberJune 30, 20172022 was below the U.S. statutory tax rate of 35%21% primarily due to no tax applied to the tax effectpre-tax income of the noncontrolling interest in MP GOM offset by exploration expenses in certain foreign jurisdictions not fully deductible from losses at the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by the U.S.in which no income tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate of 35% primarily due to an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items. During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise. Note I – Income Taxes (Contd.)The effective tax rate for the three-month period ended September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized. The effective tax rate for the nine-month period ended September 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits 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 gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company has paid amounts into escrow, and may from time to time pay more amounts16NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note K – Income Taxes (Continued)into escrow, in order to continue tax disputes with the relevant taxing authorities. As of SeptemberJune 30, 2017,2023, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United StatesU.S. – 2014;2016; Canada – 2012;2016; and Malaysia – 2010;2016. Following the sale in 2019, the Company has retained certain possible liabilities and United Kingdom – 2015.Note JL – Financial Instruments and Risk ManagementMurphy, oftenat times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were accounted for as hedges andCommodity Price RisksDuring the gain or loss associated with recordingsecond quarter of 2023, 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 todid not have any outstanding crude oil it produces and sells. derivative contracts.During the first nine months 2017 and 2016,second quarter of 2022, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production.swaps and collar contracts. Under thesethe swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At September 30, 2017,price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also matured monthly, the Company had 22,000 barrels per day in WTI crude oil swap financialpurchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar 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 increased the loss before income taxesrequired payments by $3.2 million 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 financial contracts maturing ratably during 2016. At September 30, 2016,if the fair value of WTI contracts of $0.2 millionNYMEX average closing price was included in Accounts Receivable. The impact of markingabove the ceiling price or payments to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million forCompany if the nine-month period ended September 30, 2016.12NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)Note J – Financial Instruments and Risk Management (Contd.)The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at SeptemberJune 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, 20172023 and December 31, 2016, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.(3,226) (48,864) (73) nine-monthsix-month periods ended SeptemberJune 30, 20172023 and 2016,2022, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.Gain (Loss) Gain (Loss) (Thousands of dollars) Statements of Operations Location Three Months Ended
June 30,Six Months Ended
June 30,Type of Derivative Contract 2023 2022 2023 2022 (13,573) 11,871 50,365 (22,678) 143 73 26,929 (13,573) 12,014 50,438 4,251 Commodity swaps Commodity swaps Loss on derivative instruments $ – $ (46,552) $ – $ (202,911) Commodity collars Commodity collars Loss on derivative instruments – (56,516) – (220,934) 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.17NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note L – Financial Instruments and Risk Management (Continued)The carrying value of assets and liabilities recorded at fair value on a recurring basis at SeptemberJune 30, 20172023 and December 31, 20162022, 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 June 30, 2023 December 31, 2022 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 15,273 $ – $ – $ 15,273 $ 15,135 $ – $ – $ 15,135 $ 15,273 $ – $ – $ 15,273 $ 15,135 $ – $ – $ 15,135 The fair value of WTI crude oil derivative contracts in 2017 and 2016 was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and other operating revenues in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling“Selling and general expensesexpenses” in the Consolidated Statements of Operations.As of June 30, 2023, there were no outstanding commodity West Texas Intermediate (WTI) crude oil swaps and collars contracts subject to fair value measurement.As of December 31, 2022, there were no outstanding commodity (WTI crude oil) swaps and collars contracts subject to fair value measurement. The liabilities associated with these contracts have been finalized as of December 31, 2022 and were based on realized WTI pricing. The commodity swaps and collars liability as of December 31, 2022 was $19.6 million and $2.3 million, respectively, and recorded as “Accounts payable” in the Consolidated Balance Sheets.In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG). Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds were exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020; however, the threshold was met in 2021 and 2022. The obligation period related to LLOG revenue-related contingent consideration ended in 2022, with final payments made in the first half of 2023.In 2018, the Company, through a subsidiary, acquired Gulf of Mexico producing assets from Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A. Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $150 million if certain price and production thresholds were exceeded beginning in 2019 through 2025; and $50 million carry for PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. The price and production thresholds were not exceeded for 2019 and 2020; however, the thresholds were met in 2021 and 2022. As of December 31, 2021, Murphy had completely funded the carried interest. As of December 31, 2022, the $150 million obligation limit was achieved and paid in the first half of 2023.As at June 30, 2023, the Company had no remaining liabilities relating to prior acquisitions from PAI and LLOG. As at December 31, 2022, the Company’s liabilities with PAI and LLOG were based on realized inputs of volumes and pricing as a result of reaching contractual thresholds or time limitations that ended in 2022. As a result, the related liabilities as at December 31, 2022 of $192.7 million were no longer subject to fair value measurement. The liability remaining was included in “Other accrued liabilities” in the Consolidated Balance Sheets. During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration payments, thereby reducing the liability balance to nil as at June 30, 2023. In the Consolidated Statement of Cash Flows, $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities”.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 SeptemberJune 30, 20172023 and December 31, 2016.2022.1418NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)(CONTINUED)Note JL – Financial Instruments and Risk Management (Contd.)Fair Values – NonrecurringAs a result(Continued)off-balance sheet exposures relating to certain letters 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.credit. The fair value informationof these, which represents fees associated with these impaired properties is presented inobtaining the following table.instruments, was nominal.71,967 167,055 95,088 June 30, December 31, 2023 2022 (Thousands of dollars) Carrying
AmountFair
ValueCarrying
AmountFair
ValueFinancial liabilities: Current and long-term debt $ 1,824,226 $ 1,728,376 $ 1,823,139 $ 1,668,216 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 Loss“Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 20162022 and SeptemberJune 30, 20172023 and the changes during the nine-monthsix-month period ended SeptemberJune 30, 20172023 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, 2022 $ (418,230) $ (116,456) $ (534,686) Components of other comprehensive income (loss): Before reclassifications to income 36,752 – 36,752 Reclassifications to income ¹ – 2,151 2,151 Net other comprehensive income (loss) 36,752 2,151 38,903 Balance at June 30, 2023 $ (381,478) $ (114,305) $ (495,783) 1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017$2,669 thousand are included in the computation of net periodic benefit expense.expense for the six-month period ended June 30, 2023. See Note GH for additional information. Related income taxes of $3,873 for the nine-month period ended September 30, 2017$518 thousand are included in Income“Income tax expense.2Reclassifications before taxesexpense (benefit)” on the Consolidated Statements of $2,222Operations for the nine-monthsix-month period ended SeptemberJune 30, 2017 are included in Interest expense, net. Related income taxes2023.19NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)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, regulations and regulationsgovernment action intended for the promotion of safety and the protection and/or remediation of the environment;environment including in connection with the purported causes or potential impacts of climate change; 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 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 (GHG) 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 adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.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 GHG 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, 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 to20NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)Note N – Environmental and Other Contingencies (Continued)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 (including litigation related to climate change), 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 portion21Note 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).The Company has accounted for its former United Kingdom (U.K.) and U.S. refining and marketing operations as discontinued operations for all periods presented.Total Assets at June 30, 2023 Three Months Ended June 30, 2023 Three Months Ended June 30, 2022 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ Exploration and production ¹ 5,439.1 195.9 (19.9) 201.8 (27.1) United States $ 6,963.3 $ 696.2 168.9 $ 978.0 491.5 1,711.1 81.9 (3.2) 80.9 (4.8) Canada 2,234.7 118.3 2.5 206.6 47.2 1,755.3 220.5 67.7 202.7 65.0 139.9 (11.0) 0.2 (8.1) Other 227.6 — (32.3) 13.7 (3.5) 9,045.4 498.3 33.6 485.6 25.0 Total exploration and production 9,425.6 814.5 139.1 1,198.3 535.2 1,124.2 (99.9) (0.1) (39.6) Corporate 822.8 0.1 (46.6) (97.2) (124.8) 10,169.6 498.3 (66.3) 485.5 (14.6) Continuing operations Continuing operations 10,248.4 814.6 92.5 1,101.1 410.4 23.2 0.4 (1.6) Discontinued operations, net of tax 1.2 – (0.6) – (0.9) 10,192.8 498.3 (65.9) 485.5 (16.2) Total $ 10,249.5 $ 814.6 91.9 $ 1,101.1 409.5 Six Months Ended June 30, 2023 Six Months Ended June 30, 2022 (Millions of dollars) External
RevenuesIncome
(Loss)External
RevenuesIncome
(Loss)Exploration and production ¹ Exploration and production ¹ 696.7 11.0 520.2 (158.5) United States $ 1,378.5 394.9 $ 1,685.4 744.4 388.1 102.6 264.4 (36.9) Canada 274.1 24.4 372.7 69.9 594.4 173.9 541.4 135.1 (10.9) 0.2 (39.2) Other 3.6 (37.6) 13.7 (47.7) 1,679.2 276.6 1,326.2 (99.5) Total exploration and production 1,656.2 381.7 2,071.8 766.6 4.0 (302.8) 3.5 (111.7) Corporate 0.1 (75.2) (417.8) (421.1) 1,683.2 (26.2) 1,329.7 (211.2) Continuing operations Continuing operations 1,656.3 306.5 1,654.0 345.5 1.2 (0.8) Discontinued operations, net of tax – (0.3) – (1.5) 1,683.2 (25.0) 1,329.7 (212.0) Total $ 1,656.3 306.2 $ 1,654.0 344.0 *1 Additional details about results of oil and natural gas operations are presented in the tablestable on pages 2927 and 3028.Note O – New Accounting Principles AdoptedBusiness CombinationsIn January 2017,22SummaryMurphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU)three months ended June 30, 2023 was $92.5 million, compared to clarify$410.4 million in the definitionin the second quarter of 2022, reflecting a business to assist entitiesdecrease of $317.9 million. Lower net income from continuing operations was largely driven by lower revenues and other income ($286.5 million), increases 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 businessexploration expenses ($100.6 million) and higher lease operating expenses ($46.9 million), partially offset 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 thelower income tax consequences, classificationexpense ($70.2 million). Lower revenues resulted from lower pricing, partially offset by higher sales volumes. Higher exploration costs were the result of awards as either equity or liabilities,dry hole expenses for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa and classification within the statementexpensing of cash flows. The amendmentspreviously suspended exploration costs for the Cholula -1 EXP well in this ASUMexico. Increases in lease operating expenses were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Thethe result of higher sales volumes while lower income tax expense was the result of lower pre-tax income.For the six months ended June 30, 2023, 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 exercisesreported net income from continuing operations 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$306.5 million, compared 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$345.5 million in the same line item asperiod of 2022, reflecting a decrease of $39.0 million. Lower net income from continuing operations was largely driven by higher lease operating expenses ($110.1 million) and increases in exploration expenses ($63.3 million), partially offset by lower other current employee compensation costsoperating expense ($125.9 million). Total revenues and other components of those benefit costs be presented separately from the service cost componentincome were consistent period over period as higher sales volumes and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pensionno realized 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 retrospectiveunrealized losses on derivative instruments were offset by lower pricing for the presentationsix months ended June 30, 2023. Increased lease operating expenses relate to higher sales volumes and additional costs associated with workover and maintenance activities at the Gulf of Mexico operations. Higher exploration costs were the componentsresult of these benefit costs and prospectivedry hole expense for the capitalizationChinook #7 exploration well in the Gulf of only service costs. Early adoption is permitted. The Company does not believeMexico, the applicationpurchase of this accounting standard will have a material impact on its consolidated financial statements.Revenue from Contracts with CustomersIn May 2014,seismic data for Côte d’Ivoire in offshore Africa, and the FASB issued an ASUexpensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico. Lower other expenses were due to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirementslower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.For the three months ended June 30, 2023, West Texas Intermediate (WTI) crude oil prices averaged approximately $73.78 per barrel (compared to $108.41 in the second quarter of 2022 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$76.13 in the first quarter of 2018 using either2023). The average price for WTI in June of 2023 was approximately $70.27 per barrel, reflecting a 39% reduction from June of 2022 and a 4% reduction from the modified retrospective or cumulative effect transition method.average price from March of 2023. The Company has performed a reviewaverage price in July 2023 was $76.03 per barrel. As of contractsclose on August 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were $80.68 and $76.93 per barrel, respectively.For the three months ended June 30, 2023, the New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged approximately $2.12 per barrel (compared to $7.39 in eachthe second quarter of its revenue streams2022 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$2.67 in the first quarter of 20192023). The average price for NYMEX natural gas in June of 2023 was approximately $2.12 per barrel, reflecting a 72% reduction from June of 2022 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, proceeds9% reduction from the settlementaverage price from March of insurance claims, proceeds from2023. As of close on August 1, 2023, the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.During the three-month and nine-month periods ended September 30, 2017, worldwide benchmark oil andNYMEX natural gas forward curve prices for the remainder of 2023 and 2024 were above average comparable benchmark prices during 2016. Although prices were above 2016 levels, unrealized losses from foreign exchange movements along with higher tax expense on earnings of foreign subsidiaries more than offset this increase in revenue in the third quarter.For the three months ended SeptemberJune 30, 2017,2023, the Company produced 154191 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$362.3 million in capital expenditureexpenditures (on a value of work done basis), which included $32.3 million in acquisition-related capital. Acquisition-related capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs and seismic data for Côte d’Ivoire in offshore Africa.For the six months ended June 30, 2023, the Company produced 185 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $698.3 million in capital expenditures (on a value of work done basis), which included acquisition capital of $32.3 million. Acquisition capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa. During the three and six months ended June 30, 2023, crude oil and condensate, natural gas and natural gas liquids (NGL) volumes from continuing operations were higher than the comparable prior year periods. The increase in production volumes was primarily due to higher production from Khaleesi, Mormont, Samurai field development project, reflecting a full second quarter of production in 2023 (the project started in Q2 2022) and23ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)increased production from new wells added since the second quarter of 2022. In addition, there were higher gas volumes at Tupper Montney related to new well production. For the three and six months ended June 30, 2023, revenue from production was 30% lower and 19% lower, respectively, compared to the same periods in 2022, primarily driven by the decrease in prices.For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the third quarter of 2017 primarilyKodiak field in the United States and Canada.Gulf of Mexico. The Company reported a net lossincome from continuing operations of $65.9$410.4 million for the three months ended SeptemberJune 30, 2017, which2022; this amount included a foreign exchange after-tax lossgains on unrealized mark to market revaluations on commodity price swap and collar positions of $43.9$69.6 million principallyand after-tax losses on intercompany loanscontingent consideration of $25.1 million.During the second quarter of 2022, the Company achieved first production at the Khaleesi, Mormont, Samurai field development project in the quarter andGulf of Mexico, with production flowing through the Murphy-operated King’s Quay floating production system.In June 2022, the Company also acquired an after-tax loss of $11.8 millionadditional 11.0% working interest (there is no noncontrolling interest) in the third quarter relating to crude oil derivative contracts.For the nine-month periodsix months ended SeptemberJune 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 162 thousand barrels of oil equivalent per day for the nine-month 2017 period(including noncontrolling interest) from continuing operations and invested $702$621.9 million in capital expenditures principally(on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat -1 exploration well in the United States and Canada.Brazil. The Company incurred a non-cash deferred tax expense inreported net income from continuing operations of $345.5 million for the first ninesix months ended June 30, 2022. This amount included after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration adjustments of 2017$79.3 million and $102.3 million, respectively.24ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of OperationsResults of OperationsMurphy’s income (loss) by type of business is presented below.Income (Loss) Three Months Ended
June 30,Six Months Ended
June 30,(Millions of dollars) 2023 2022 2023 2022 33.6 25.0 276.6 (99.5) Exploration and production $ 139.1 $ 535.2 $ 381.7 $ 766.6 (99.9) (39.6) (302.8) (111.7) Corporate and other (46.6) (124.8) (75.2) (421.1) (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 from continuing operations Income from continuing operations 92.5 410.4 306.5 345.5 Discontinued operations ¹ Discontinued operations ¹ (0.6) (0.9) (0.3) (1.5) Net income including noncontrolling interest Net income including noncontrolling interest $ 91.9 $ 409.5 $ 306.2 $ 344.0 Third quarter 2017 vs. 2016For the third quarter of 2017, Murphy’s net loss was $65.9 million ($0.38 per diluted share) compared to net loss of $16.2 million ($0.09 per diluted share) in the third quarter of 2016. Loss from continuing operations fell lower from a loss of $14.6 million ($0.08 per diluted share) in the 2016 quarter to a loss of $66.3 million ($0.38 per diluted share) in the 2017 period. The Company’s exploration and production (E&P) continuing operations earned $33.6 million in the 2017 quarter compared to earnings of $25.0 million in the 2016 quarter. The E&P results in the 2017 quarter were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices, lower lease operating expenses, lower depreciation expense and lower dry hole costs, partially offset by lower volume sold, higher selling and general expenses and higher deferred tax expense on earnings of foreign subsidiaries. The corporate function had after-tax costs of $99.9 million in the 2017 third quarter compared to after-tax costs of $39.6 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs in the current quarter. The third quarter of 2017 included gains from discontinued operations of $0.4 million ($0.00 per diluted share) compared to losses from discontinued operations of $1.6 million ($0.01 per diluted share) in the third quarter of 2016.Nine months 2017 vs. 2016For the first nine months of 2017, Murphy’s net loss was $25.0 million ($0.14 per diluted share) compared to a net loss of $212.0 million ($1.24 per diluted share) for the same period in 2016. Loss from continuing operations improved from a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016 to a loss of $26.2 million ($0.15 per diluted share) in 2017. In the first nine months of 2017, the Company’s E&P continuing operations earned $276.6 million compared to a loss of $99.5 million in the same period of 2016. The results for the first nine months of 2017 were favorably 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 Exploration and Production (E&P) continuing operations are presented by geographic segment below.Income (Loss) Three Months Ended
June 30,Six Months Ended
June 30,(Millions of dollars) 2023 2022 2023 2022 Exploration and production United States $ 168.9 $ 491.5 $ 394.9 $ 744.4 Canada 2.5 47.2 24.4 69.9 Other (32.3) (3.5) (37.6) (47.7) Total $ 139.1 $ 535.2 $ 381.7 $ 766.6 25ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)Other key performance metricsThe after-taxCompany uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and Adjusted EBITDA. Management uses EBITDA and Adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and Adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with GAAP.Three Months Ended
June 30,Six Months Ended
June 30,(Millions of dollars) 2023 2022 2023 2022 Net income attributable to Murphy (GAAP) $ 98.3 $ 350.6 $ 289.9 $ 237.2 Income tax expense 34.9 105.1 88.7 88.1 Interest expense, net 29.9 41.4 58.7 78.7 Depreciation, depletion and amortization expense ¹ 210.1 188.2 399.3 344.8 EBITDA attributable to Murphy (Non-GAAP) 373.2 685.3 836.6 748.8 Write-off of previously suspended exploration well 17.1 — 17.1 — Accretion of asset retirement obligations ¹ 10.1 10.2 20.0 20.7 Foreign exchange loss (gain) 7.9 (8.0) 8.3 (8.0) Mark-to-market loss on contingent consideration 3.2 31.7 7.1 129.8 Discontinued operations loss 0.6 0.9 0.3 1.5 Mark-to-market (gain) loss on derivative instruments – (88.1) – 100.4 Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 412.1 $ 632.0 $ 889.4 $ 993.2 1 Depreciation, depletion and amortization expense and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).26ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2023 AND 2022(Millions of dollars) UnitedStates 1Canada Other Total Three Months Ended June 30, 2023 Oil and gas sales and other operating revenues $ 696.2 $ 105.3 $ — $ 801.5 Sales of purchased natural gas — 13.0 – 13.0 Lease operating expenses 156.5 37.5 0.1 194.1 Severance and ad valorem taxes 12.4 0.4 – 12.8 Transportation, gathering and processing 39.9 20.1 – 60.0 Costs of purchased natural gas — 9.7 – 9.7 Depreciation, depletion and amortization 178.0 35.0 — 213.0 Accretion of asset retirement obligations 9.3 1.9 0.1 11.3 Exploration expenses Dry holes and previously suspended exploration costs 79.8 – 15.8 95.6 Geological and geophysical 0.4 0.1 10.0 10.5 Other exploration 1.7 — 5.3 7.0 81.9 0.1 31.1 113.1 Undeveloped lease amortization 2.1 — 0.6 2.7 Total exploration expenses 84.0 0.1 31.7 115.8 Selling and general expenses (1.9) 4.7 2.6 5.4 Other 0.5 5.4 1.4 7.3 Results of operations before taxes 217.5 3.5 (35.9) 185.1 Income tax provisions (benefits) 48.6 1.0 (3.6) 46.0 Results of operations (excluding Corporate segment) $ 168.9 $ 2.5 $ (32.3) $ 139.1 Three Months Ended June 30, 2022 Oil and gas sales and other operating revenues $ 977.8 $ 156.8 $ 13.7 $ 1,148.3 Sales of purchased natural gas 0.2 49.8 – 50.0 Lease operating expenses 109.5 36.9 0.9 147.3 Severance and ad valorem taxes 17.3 0.3 – 17.6 Transportation, gathering and processing 32.3 17.6 – 49.9 Costs of purchased natural gas 0.2 47.7 – 47.9 Depreciation, depletion and amortization 153.7 35.6 3.4 192.7 Accretion of asset retirement obligations 9.1 2.4 0.1 11.6 Exploration expenses Dry holes and previously suspended exploration costs (0.7) – 2.0 1.3 Geological and geophysical – 0.1 0.8 0.9 Other exploration 2.9 0.3 6.0 9.2 2.2 0.4 8.8 11.4 Undeveloped lease amortization 2.3 – 1.4 3.7 Total exploration expenses 4.5 0.4 10.2 15.1 Selling and general expenses 3.2 3.8 2.1 9.1 Other 35.3 (2.3) – 33.0 Results of operations before taxes 612.9 64.2 (3.0) 674.1 Income tax provisions 121.4 17.0 0.5 138.9 Results of operations (excluding Corporate segment) $ 491.5 $ 47.2 $ (3.5) $ 535.2 1 Includes results attributable to a noncontrolling interest in MP GOM.27ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2023 AND 2022(Millions of dollars) United
States 1Canada Other Total Six Months Ended June 30, 2023 Oil and gas sales and other operating revenues $ 1,378.5 $ 217.2 $ 3.6 $ 1,599.3 Sales of purchased natural gas – 56.8 – 56.8 Lease operating expenses 319.2 74.3 0.7 394.2 Severance and ad valorem taxes 23.5 0.7 – 24.2 Transportation, gathering and processing 77.3 36.5 – 113.8 Costs of purchased natural gas – 41.9 – 41.9 Depreciation, depletion and amortization 338.2 66.7 0.9 405.8 Accretion of asset retirement obligations 18.4 3.9 0.2 22.5 Exploration expenses Dry holes and previously suspended exploration costs 79.6 – 16.9 96.5 Geological and geophysical 0.7 0.1 10.5 11.3 Other exploration 3.3 0.1 9.4 12.8 83.6 0.2 36.8 120.6 Undeveloped lease amortization 4.1 0.1 1.2 5.4 Total exploration expenses 87.7 0.3 38.0 126.0 Selling and general expenses 4.5 7.1 2.8 14.4 Other 9.9 9.7 1.4 21.0 Results of operations before taxes 499.8 32.9 (40.4) 492.3 Income tax provisions (benefits) 104.9 8.5 (2.8) 110.6 Results of operations (excluding Corporate segment) $ 394.9 $ 24.4 $ (37.6) $ 381.7 Six Months Ended June 30, 2022 Oil and gas sales and other operating revenues $ 1,685.2 $ 286.1 $ 13.7 $ 1,985.0 Sales of purchased natural gas 0.2 86.6 – 86.8 Lease operating expenses 209.4 73.8 0.9 284.1 Severance and ad valorem taxes 31.5 0.7 – 32.2 Transportation, gathering and processing 61.5 35.3 – 96.8 Costs of purchased natural gas 0.2 81.6 – 81.8 Depreciation, depletion and amortization 280.2 69.8 3.5 353.5 Accretion of asset retirement obligations 18.5 4.9 0.1 23.5 Exploration expenses Dry holes and previously suspended exploration costs (0.7) – 34.8 34.1 Geological and geophysical 2.6 0.1 1.0 3.7 Other exploration 4.4 0.4 12.1 16.9 6.3 0.5 47.9 54.7 Undeveloped lease amortization 4.7 0.1 3.2 8.0 Total exploration expenses 11.0 0.6 51.1 62.7 Selling and general expenses 11.5 8.9 4.5 24.9 Other 138.1 2.8 0.4 141.3 Results of operations before taxes 923.5 94.5 (46.8) 971.2 Income tax provisions 179.1 24.6 0.9 204.6 Results of operations (excluding Corporate segment) $ 744.4 $ 69.9 $ (47.7) $ 766.6 1 Includes results attributable to a noncontrolling interest in MP GOM.28ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)Exploration and ProductionSecond quarter 2023 vs. 2022All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.U.S. E&P operations reported earnings of $168.9 million in the second quarter of 2023 compared to earnings of $491.5 million in the second quarter of 2022. Results were $322.6 million unfavorable in the 2023 period compared to the 2022 period primarily due to lower revenues ($281.6 million), higher dry hole and previously suspended exploration costs ($80.5 million), higher lease operating expenses ($47.0 million) and higher depreciation, depletion and amortization expense (DD&A) ($24.3 million), partially offset by lower other expense ($34.8 million) and lower income tax expense ($72.8 million). Lower revenues were primarily due to lower realized prices at Eagle Ford Shale and the Gulf of Mexico, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells at the Khaleesi, Mormont, Samurai development project. Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons. Higher lease operating expenses were primarily due to increased sales volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations. Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico. Lower other expense was primarily due to a lower contingent consideration adjustment of $3.2 million in 2023 (2022: $31.7 million) as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L). Lower income tax expense was a result of lower pre-tax income.Canadian E&P operations reported earnings of $2.5 million in the second quarter of 2023 compared to earnings of $47.2 million in the second quarter of 2022. Results were unfavorable $44.7 million compared to the 2022 period primarily due to lower revenues ($51.5 million), partially offset by lower income tax expense ($16.0 million). Lower revenues were due to lower oil and gas pricing in the second quarter of 2023 and lower sales volumes primarily as a result of natural decline at Kaybob Duvernay, partially offset by higher natural gas sales volumes and lower royalties at Tupper Montney. Lower income tax expense was a result of lower pre-tax income.Other international E&P operations reported a loss from continuing operations of $32.3 million in the second quarter of 2023 compared to a loss of $3.5 million in the second quarter of 2022. The result was $28.8 million unfavorable versus the 2022 period primarily due to higher exploration expenses ($21.5 million) and lower revenues from Brunei ($13.7 million). Higher exploration expenses related to the purchase of seismic data for Côte d’Ivoire in offshore Africa and writing off previously suspended exploration costs for the Cholula -1 EXP well in Mexico.Six months 2023 vs. 2022All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.U.S. E&P operations reported earnings of $394.9 million for the six months ended June 30, 2023, compared to earnings of $744.4 million for the six months ended June 30, 2022. Results were $349.5 million unfavorable in the 2023 period compared to the 2022 period, driven by lower revenues ($306.9 million), higher lease operating expenses ($109.8 million), higher dry hole and previously suspended exploration costs ($80.3 million) and higher DD&A ($58.0 million), partially offset by lower other expense ($128.2 million) and lower income tax expense ($74.2 million). Lower revenues were primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells at Khaleesi, Mormont, Samurai development project. Higher lease operating expenses related to increased sales volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations. Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons. Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico. Lower other expenses was primarily due to a lower contingent consideration adjustment of $7.1 million in 2023 (2022: $129.8 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L). Lower income tax expense was a result of lower pre-tax income.Canadian E&P operations reported earnings of $24.4 million for the six months ended June 30, 2023, compared to earnings of $69.9 million for the six months ended June 30, 2022. Results were $45.5 million unfavorable compared to the 2022 period. The current year results include lower revenues ($68.9 million), partially offset by lower income tax expense ($16.1 million). Lower revenue was primarily attributable to lower realized prices and29ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)lower volumes at Kaybob Duvernay primarily due to natural decline, partially offset by higher gas volumes at Tupper Montney related to new wells added and lower royalties. Lower income tax expense was a result of lower pre-tax income.Other international E&P operations reported a loss of $37.6 million for the six months ended June 30, 2023, compared to a loss of $47.7 million in the prior year. Results were $10.1 million favorable compared to the 2022 period primarily due to lower exploration expenses ($13.1 million), partially offset by lower revenues from Brunei ($10.1 million). Lower exploration expenses were primarily the result of higher dry hole costs in 2022 for Cutthroat -1 exploration well, partially offset by the purchase of seismic data for Côte d’Ivoire in offshore Africa in the current period. During the six months ended June 30, 2023, the Company expensed costs for the previously suspended exploration costs for Cholula -1 EXP well in Block 5 in the Gulf of Mexico, and during the same period in 2022, the Company expensed costs associated with the Cutthroat -1 exploration well in block SEAL-M-428, in the Sergipe-Alagoas Basin offshore Brazil.CorporateSecond quarter 2023 vs. 2022Corporate 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 $46.6 million in the second quarter of 2023 compared to a loss of $124.8 million in same period of 2022. The $78.2 million favorable variance was principally due to no current period losses on derivative instruments in the second quarter of 2023 compared to a loss for the same period in 2022 of $103.1 million. Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. During the second quarter of 2023 and as of June 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Favorable variances were also recorded due to lower interest expense resulting from overall lower debt levels ($11.6 million), partially offset by lower income tax benefit ($22.4 million). Lower income tax benefit was a result of lower pre-tax losses.Six months 2023 vs. 2022Corporate 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 $75.2 million for the six months ended June 30, 2023, compared to a loss of $421.1 million for the six months ended June 30, 2022. The $345.9 million favorable variance was primarily due to no current period losses on derivative instruments for the six months ended June 30, 2023, compared to a loss for the same period in 2022 ($423.8 million) and lower interest expense ($19.9 million), partially offset by lower income tax benefits ($94.4 million) and higher foreign exchange losses ($15.9 million). Interest charges are lower for the six months ended June 30, 2023,primarily due to lower overall debt levels as the Company reduced debt by $647.7 million during 2022 and the Company incurred debt redemption premiums of $3.4 million during the same period in 2022. Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. During the six months ended June 30, 2023 and as of June 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Lower income tax benefit was a result of lower pre-tax losses.30ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)Production Volumes and PricesSecond quarter 2023 vs. 2022Total hydrocarbon production from continuing operations averaged 190,695 barrels of oil equivalent per day in the second quarter of 2023, which was 10% higher than the 173,173 barrels per day produced in second quarter of 2022. The increase in production was principally due to increased production from the Gulf of Mexico primarily attributable to the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore, related primarily to new well production at Tupper Montney.Average crude oil and condensate production from continuing operations was 105,124 barrels per day in the second quarter of 2023 compared to 98,661 barrels per day in the second quarter of 2022. The increase of 6,463 barrels per day was associated with higher volumes in the Gulf of Mexico (8,595 barrels per day) principally due to a full quarter of production from the Khaleesi, Mormont, Samurai field development project in 2023 and new wells added since the second quarter of 2022. In addition, Canada production was lower (1,537 barrels per day) primarily attributable to natural well declines at Kaybob Duvernay. Eagle Ford Shale production was higher (576 barrels per day) due to new well production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.50 per barrel in the second quarter of 2023 compared to $109.25 per barrel in the same period of 2022 period, a decrease of 33%.Total production of NGL from continuing operations was 11,177 barrels per day in the second quarter of 2023 compared to 10,950 barrels per day in the second quarter of 2022. The increase of 227 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to increased production from the Khaleesi, Mormont, Samurai field development project, partially offset with lower volumes at Eagle Ford Shale for planned downtime for offset frac impacts. The average sales price for U.S. NGL was $18.71 per barrel in the second quarter of 2023 compared to $39.37 per barrel in the same period of 2022. The average sales price for NGL in Canada was $29.90 per barrel in the second quarter of 2023 compared to $63.99 per barrel in the same period of 2022. 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 446.4 million cubic feet per day (MMCFD) in the second quarter of 2023 compared to 381.4 MMCFD in the second quarter 2022. The increase of 65.0 MMCFD was primarily the result of higher volumes in Canada (64.2 MMCFD). Higher natural gas volume in Canada is primarily due to new well production and lower natural gas royalty volumes. Natural gas prices for the total Company averaged $1.92 per thousand cubic feet (MCF) in the second quarter of 2023, versus $3.90 per MCF average in the same period of 2022. Average natural gas prices in the U.S. and Canada for the second quarter of 2023 was $2.21 and $1.85 per MCF, respectively.Six months 2023 vs. 2022Total hydrocarbon production from Exploration and Production averaged 185,250 barrels of oil equivalent per day for the six months ended June 30, 2023, which represented a 15% increase from the 161,579 barrels per day produced for the six months ended June 30, 2022. The increase was principally due to increased production from the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore primarily due to new wells at Tupper Montney.Average crude oil and condensate production was 103,067 barrels per day for the six months ended June 30, 2023, compared to 91,154 barrels per day for the six months ended June 30, 2022. The increase of 11,913 barrels per day was principally due to increased production from the Gulf of Mexico largely attributable to the Khaleesi, Mormont, Samurai field development project for new wells added since the second quarter of 2022 (14,487 barrels per day). In addition, Canada production was lower (1,747 barrels per day) primarily due to natural decline at Kaybob Duvernay. Eagle Ford Shale production was lower (234 barrels per day) due to normal well decline partially offset by new well production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.65 per barrel for the six months ended June 30, 2023, compared to $102.86 per barrel in the 2022 period, and decrease of 28.4% year over year.Total production of NGL was 11,250 barrels per day for the six months ended June 30, 2023, compared to 10,150 barrels per day in the 2022 period. The average sales price for U.S. NGL was $21.44 per barrel in 202331ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)compared to $40.00 per barrel in 2022. The average sales price for NGL in Canada was $39.82 per barrel in 2023 compared to $59.23 per barrel in 2022. 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 425.6 MMCFD for the six months ended June 30, 2023, compared to 361.7 MMCFD in 2022. The increase of 63.9 MMCFD was primarily the result of higher volumes in Canada (55.6 MMCFD) and the Gulf of Mexico (12.6 MMCFD), partially offset by lower volumes at Eagle Ford Shale (4.3 MMCFD). The higher natural gas volumes in Canada were the result of new wells brought into production during the second quarter of 2023 and new wells added since the second quarter of 2022. Natural gas prices for the total Company averaged $2.28 per MCF for the six months ended June 30, 2023, versus $3.54 per MCF average in the same period of 2022. Average realized natural gas prices in the U.S. and Canada for the six months ended June 30, 2023 were $2.66 per MCF and $2.17 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 27 and28.32ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2023 and 2022.Three Months Ended
June 30,Six Months Ended
June 30,(Barrels per day unless otherwise noted) 2023 2022 2023 2022 Net crude oil and condensate United States Onshore 26,880 26,304 23,100 23,334 Gulf of Mexico 172,022 63,427 73,850 59,363 Canada Onshore 3,097 4,419 3,190 4,400 Offshore 2,913 3,128 2,687 3,224 Other 212 1,383 240 833 Total net crude oil and condensate - continuing operations 105,124 98,661 103,067 91,154 Net natural gas liquids United States Onshore 4,328 5,178 4,243 5,006 Gulf of Mexico 16,291 4,913 6,316 4,223 Canada Onshore 558 859 691 921 Total net natural gas liquids - continuing operations 11,177 10,950 11,250 10,150 Net natural gas – thousands of cubic feet per day United States Onshore 24,195 29,651 24,178 28,512 Gulf of Mexico 169,904 63,703 72,539 59,902 Canada Onshore 352,265 288,019 328,878 273,237 Total net natural gas - continuing operations 446,364 381,373 425,595 361,651 Total net hydrocarbons - continuing operations including NCI 2,3190,695 173,173 185,250 161,579 Noncontrolling interest Net crude oil and condensate – barrels per day (5,949) (7,962) (6,279) (8,044) Net natural gas liquids – barrels per day (204) (319) (218) (303) Net natural gas – thousands of cubic feet per day (1,751) (3,097) (2,051) (2,845) Total noncontrolling interest 3(6,445) (8,797) (6,839) (8,821) Total net hydrocarbons - continuing operations excluding NCI 2,3184,250 164,376 178,411 152,758 1 Includes net volumes attributable to a noncontrolling interest in MP GOM.2 Natural gas converted on an energy equivalent basis of 6:1.3 NCI – noncontrolling interest in MP GOM.33ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Results of Operations (Continued)The following table contains the weighted average sales prices for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172023 and 20162022.Three Months Ended
June 30,Six Months Ended
June 30,2023 2022 2023 2022 (Weighted average Exploration and Production sales prices) Continuing operations Crude oil and condensate – dollars per barrel United States Onshore $ 72.39 $ 110.66 $ 73.47 $ 103.39 Gulf of Mexico 173.82 109.55 73.54 102.76 Canada 2Onshore 68.50 100.51 71.46 96.84 Offshore 80.14 115.65 79.26 113.46 Other – 86.51 89.05 86.51 Natural gas liquids – dollars per barrel United States Onshore 16.60 38.29 19.28 38.30 Gulf of Mexico 120.16 40.46 22.89 41.95 Canada 2Onshore 29.90 63.99 39.82 59.23 Natural gas – dollars per thousand cubic feet United States Onshore 1.88 7.06 2.19 5.89 Gulf of Mexico 12.33 7.52 2.81 6.43 Canada 2Onshore 1.85 2.78 2.17 2.66 1 Prices 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$749.7 million for the first ninesix months of 2017ended June 30, 2023 compared to $280.3$959.2 million during the same period in 2016.2022. The improvement inlower cash provided by continuing operationsfrom operating activities in 2017of $209.5 million was primarily attributable to higher realized sales prices for the Company’s oillower revenue from production ($384.8 million), payments of contingent consideration related to prior Gulf of Mexico acquisition ($139.6 million), and gas production, lowerhigher lease operating and administrative expenses and rig cancellation payments in 2016 which are discussed below,($110.1 million), partially offset by lower volume soldrealized losses on derivative instruments ($323.5 million) and the timing of working capital settlements ($106.3 million). Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the current yearCompany’s Consolidated Statement of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and higher interest costs. Changes$60.2 million is shown in operating working capital from continuing operations increased“Financing Activities” in the Company’s Consolidated Statement of Cash Flows. As of June 30, 2023, the Company has no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.34ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Financial Condition (Continued)Cash Required by Investing ActivitiesNet cash required by $1.1investing activities, including amount expensed, was $694.8 million for the six months ended June 30, 2023 compared to $599.3 million during the first nine monthssame period in 2022. In the second quarter of 2017, compared to a use2023, the Company accrued for acquisition-related capital of cash of $152.6$32.3 million, in 2016. The use of cash in 2016 included $266.6 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015. Proceeds from sales of property and equipment generated cash of $69.1 million in 2017which consisted primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain areas of Eagle Ford Shale in South Texas, while the 2016 period generated cash of $1,154.6 million mainly related to the sale of Syncrude Canada Limited and certain midstream assets in the Tupper area of Western Canada. Other significant sources of cash included $320.8 million in the 2017 period and $712.9 million in 2016 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.27ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)Financial Condition (Contd.)Cash used for 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 millionfinal milestone payment for the nine-months ended September 30, 2017 compared to $163.6 millionBlock 15-1/05 farm-in agreement 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 CanadianVietnam following 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 proceedsapproval of the $550 million notes issueddevelopment plan and lease acquisition costs for Côte d’Ivoire in August 2017, were used to redeemoffshore Africa (also see Company’s $550 million 2.50% notessix months ended 2022, the Company acquired an 11.0% additional working interest in September 2017. The 2.50% notes had a maturity dateKodiak 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.Six Months Ended
June 30,(Millions of dollars) 2023 2022 Capital Expenditures 694.7 614.6 Exploration and production $ 688.4 $ 611.4 6.9 20.7 Corporate 9.9 10.5 701.6 635.3 Total capital expenditures $ 698.3 $ 621.9 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“Property additions and dry hole costscosts” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.Six Months Ended
June 30,(Millions of dollars) 2023 2022 706.4 781.7 Property additions and dry hole costs per cash flow statements $ 694.8 $ 552.8 Acquisition of oil and gas properties Acquisition of oil and gas properties – 46.5 37.7 32.8 Geophysical and other exploration expenses 20.0 16.3 (42.5) (179.2) Capital expenditure accrual changes and other (16.5) 6.3 701.6 635.3 Total capital expenditures $ 698.3 $ 621.9 The increase in capital expenditures in the exploration and production business in six months ended June 30, 2023 compared to the same period in 2022 was primarily attributable to development drilling activities at Eagle Ford Shale assets, development drilling at Samurai and St. Malo fields in the Gulf of Mexico, and exploration drilling at Chinook #7, Oso #1 and Longclaw #1 within the Gulf of Mexico. Costs associated with Chinook #7 were expensed to dry hole costs in the second quarter of 2023 as the Company determined there were non- commercial hydrocarbons present. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the third quarter of 2023.Cash Required by Financing ActivitiesNet cash required by financing activities was $176.6 million for the six months ended June 30, 2023 compared to $447.5 million during the same period in 2022. In 2023, the cash used in financing activities was principally for the payment of contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section, cash dividends to shareholders of $0.55 per share ($85.9 million) and distributions to the non-controlling interest in the Gulf of Mexico ($16.0 million).As of June 30, 2023 and in the event it is required to fund investing activities from borrowings, the Company has $769.6 million available on its committed RCF.35ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)Financial Condition (Continued)Working CapitalAs of June 30, 2023, working capital (total current assets less total current liabilities) at September 30, 2017 was $615.6amounted to a net working capital liability of $165.4 million, $558.8$120.1 million morelower than December 31, 2016,2022, with the increasefavorable decrease primarily attributable to lower other accrued liabilities ($307.8 million), partially offset with higher accounts payable ($40.3 million), higher operating lease liabilities ($37.9 million) and a lower cash balance ($122.6 million). Lower accrued liabilities were primarily due to payments made for contingent consideration obligation from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made during the Company redeemingsix months ended June 30, 2023. Higher accounts payable was primarily due to increased drilling and completions activities and an increase in current payables for abandonment activities, partially offset by the $550 milliondecrease in 2.50% notesunrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts outstanding during 2023. Higher current operating lease liabilities were associated with scheduled rate increases for a drilling vessel resulting in September 2017, higher cash balances and lower accounts payable.Capital EmployedAt SeptemberJune 30, 2017,2023, long-term debt of $2,908.3$1,823.5 million had increased by $485.5$1.1 million compared to December 31, 2016. 2022, primarily as a result of normal debt issuance cost amortization. The total of the fixed-rate notes had a weighted average maturity of 7.2 years and a weighted average coupon of 6.1%.A summary of capital employed at SeptemberJune 30, 20172023 and December 31, 20162022 follows.June 30, 2023 December 31, 2022 (Millions of dollars) Amount % Amount % Capital employed 2,908.3 36.9 2,422.8 33.0 Long-term debt $ 1,823.5 25.8 % $ 1,822.4 26.7 % 4,980.1 63.1 4,916.7 67.0 Murphy shareholders' equity Murphy shareholders' equity 5,234.3 74.2 % 4,994.8 73.3 % 7,888.4 100.0 7,339.5 100.0 Total capital employed $ 7,057.8 100.0 % $ 6,817.2 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. At SeptemberU.S. As of June 30, 2017, Cash2023, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5$76.9 million, in Canada and $261.6 million in Malaysia. In addition, $17.0 millionthe majority of cashwhich 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.Mexico ($21.1 million), Canada ($20.8 million), U.K. ($11.8 million), Brunei ($8.8 million) and Spain ($8.2 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to incentivize oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada currently collects a 5% withholding tax onFinancial Condition (Contd.)cashearnings repatriated to the United States through a dividend to the U.S. parent. See the “Corporate” section on page On July 31, of this Form 10-Q report regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.Accounting and Other MattersBusiness CombinationsIn January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.Compensation – Stock CompensationIn March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Compensation – Retirement BenefitsIn March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.Revenue from Contracts with CustomersIn May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU. While 2023 the Company does not currently expect net earningsentered into a purchase and sale agreement to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impactsell a portion 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 leaseour operated non-core Kaybob Duvernay assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash consideration of C$150 million. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASUtransaction 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 guidanceanticipated to close 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 worldwide crude oil prices in October 2017 have slightly improved from the average prices during the third quarter of 2017. North American natural gas2023, subject to closing conditions and adjustments.Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial StatementsOutlookPrices for the Company’s primary products are often volatile. The price of crude oil is primarily affected by the levels of supply and demand for energy. As discussed in the Summary section on page 23, lower average crude oil price during the second quarter of 2023 directly impacts the Company’s product revenue from sales. NYMEX WTI pricing for recent and comparable periods was as follows: Q2 2023 $73.78; Q1 2023 $76.13; Q2 2022 $108.41. As of close on August 1, 2023 the NYMEX WTI forward curve prices decreased slightlyfor the remainder of 2023 and 2024 were lower at $80.68 and $76.93 per barrel, respectively; however, we cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in October fromlower profits and operating cash flows. For the 2017 third quarter. The Company expects its total oil and natural gasquarter of 2023, production is expected to average 170,000 – 172,000between 188.0 and 196.0 thousand barrels of oil equivalent per day in the fourth quarter 2017. equivalents (MBOEPD), excluding noncontrolling interest.36The Company currently anticipates totalCompany’s capital expenditure spend for 2023 is expected to be between $950.0 million and $1,025.0 million, excluding noncontrolling interest. Capital and other expenditures are routinely reviewed and planned capital expenditures formay be adjusted to reflect differences between budgeted and forecast cash flow during the full year 2017 toyear. Capital expenditures may also be approximately $940 million.remaining capital program in 20172023 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), including proceeds from the Company’s divestiture of a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction. Details of the framework can be found in the “Capital Allocation Framework” section 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 RCF (see Note E).As of NovemberAugust 1, 2017,2023, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:Contract orAverage
(MMcf/d)Price/Mcf Remaining Period CommoditiesLocationDatesVolumes per DayAverage PricesEnd Date U.S. OilWest Texas IntermediateOct. – Dec. 2017250 22,000 bbls/d$50.41 per bbl.7/1/2023 12/31/2023 U.S. OilWest Texas IntermediateJan. – Dec. 2018162 7,000 bbls/d$51.92 per bbl.1/1/2024 12/31/2024 Canada Natural Gas Fixed price forward sales 25 US$1.98 7/1/2023 10/31/2024 Natural Gas TCPL–NOVA SystemJul. – Dec. 2017124 mmcf/dC$2.97 per mcfNatural GasTCPL–NOVA SystemJan. – Dec. 201859 mmcf/dC$2.81 per mcfNatural GasAlberta AllianceNov. 2017 – Mar. 201820 mmcf/dUS$3.51 per mcf**Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate.2837Forward-Looking StatementsThis Form 10-Q contains forward-looking statements as defined inwithin the meaning of 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 and plans, are subject to inherent risks, uncertainties and uncertainties.assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from thosethe expectations expressed or implied in ourby such forward-looking statements, 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, banking system 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 Murphy’s 2016“Risk Factors” in our most recent Annual Report on Form 10-K on filefiled with the U.S. Securities and3638ITEM 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, at times, makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.There were no derivative commodity transactionscontracts in place at SeptemberJune 30, 2017 covering certain future U.S. crude oil sales volumes in 2017. A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net receivable associated with these derivative contracts by approximately $21.9 million, while a 10% decrease would have increased the recorded net receivable by a similar amount.There were no derivative foreign exchange contracts in place at SeptemberJune 30, 2017.2023.Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.During the quarter ended SeptemberJune 30, 2017,2023, 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.39Murphy 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 20162022 Form 10-K filed on February 24, 2017.27, 2023. The Company has not identified any additional risk factors not previously disclosed in its 20162022 Form 10-K report.The Exhibit Index on page 3842 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.40SIGNATUREPursuant 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)August 3, 2023EXHIB(Date)41EXHIBIT 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. 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). Exhibits other than those listed above have been omitted since they are either not required or not applicable.2942