☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
For the fiscal year ended | December 31, | |||||||
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
For the transition period from to | ||||||||
| Delaware | 71-0361522 | ||||||||
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(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | ||||||||
| 9805 Katy Fwy, Suite G-200 | 77024 | ||||||||
| Texas | (Zip Code) | |||||||
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(Address of principal executive offices) | |||||||||
| (281) | 675-9000 | ||||||||
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Registrant’s telephone number, including area code: (870) 862-6411
Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
Common Stock, $1.00 Par Value | MUR | New York Stock Exchange | ||||||
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Large accelerated filer | ☒ | Accelerated filer | ☐ | ||||||||||||||||||||||||||
Non-accelerated filer | ☐ | Smaller reporting company | ☐ | ||||||||||||||||||||||||||
Emerging growth company | ☐ | ||||||||||||||||||||||||||||
$4,406,165,207. 152,755,027. Item 1A. Item 9. greenhouse gas (GHG) emissions and impact on the environment as well as other social and environmental aspects of its business. See targeted areas worldwide. Brunei. barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was an increase of 10.0% compared to 2022. Kaybob Duvernay mineral rights. Daily production in Proved Reserves Crude Natural Gas Oil Liquids Natural Gas Proved Developed Reserves: (MMBOE) (BCF) United States Canada Malaysia Total proved developed reserves Proved Undeveloped Reserves: United States Canada Malaysia – Total proved undeveloped reserves Total proved reserves Total Total Proved Proved Undeveloped (Millions of oil equivalent barrels) Reserves Reserves Beginning of year Revisions of previous estimates Extensions and discoveries Improved recovery – Conversions to proved developed reserves – Purchases of properties Production – End of year Onshore Canada. The Company currently operates deepwater fields in the Gulf of Mexico that have Larger Corporate Reserves group. Murphy provides annual training to all various business processes related to reserves. report. Developed Undeveloped Total Area (Thousands of acres) Gross Net Gross Net Gross Net United States – Onshore – Gulf of Mexico Total United States Canada – Onshore – Offshore Total Canada Malaysia Mexico – – Brazil – – Australia – – Brunei – – Vietnam – – Spain – – Totals Oil Wells Gas Wells Gross Net Gross Net Country United States Canada Malaysia Totals United States Canada Malaysia Other Totals Pro- Pro- Pro- Pro- Pro- ductive Dry ductive Dry ductive Dry ductive Dry ductive Dry 2017 Exploratory - - - - - - - - - - Development - - - - - - - 2016 Exploratory - - - - - - - - Development - - - - - - 2015 Exploratory - - - - Development - - - - - - Exploratory Development Total Country Gross Net Gross Net Gross Net United States - - Canada - - Totals - - results, cash flows and financial condition. market conditions; Brent. recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect mature, potentially negatively impacting our liquidity. grow. talent. respective year as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs. Estimates of economically recoverable crude oil, NGL and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. were audited by third-party auditors. operations. Contents gas, which could become more significant as a result of climate change. This risk extends to actions and operational hazards of other operators in the industry, which may also impact the Company. insurance, see Risk Factors, “General Risk Factors – Murphy’s insurance may not be adequate to offset costs associated with certain events, and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase. ” demand for our products or otherwise affect our results of operations or financial condition. ” December 31, 2023. This exposure to currencies other than the U.S. dollar functional currency can lead to impacts on consolidated financial results from foreign currency translation. Company’s legal proceedings are included in Board. 2022. Murphy Oil Corporation $ S&P 500 Index Peer Group (Thousands of dollars except per share data) Results of Operations for the Year 2017 2016 2015 2014 2013 Sales and other operating revenues $ Net cash provided by continuing operations Income (loss) from continuing operations Net income (loss) Cash dividends – diluted Per Common share – diluted Income (loss) from continuing operations $ Net income (loss) Average common shares outstanding (thousands) – diluted Cash dividends per Common share Capital Expenditures for the Year 1 Continuing operations Exploration and production $ 2 Corporate and other Discontinued operations – – $ Financial Condition at December 31 Current ratio Working capital (deficit) $ Net property, plant and equipment Total assets Long-term debt Stockholders’ equity Per share Long-term debt – percent of capital employed 3 Stockholder and Employee Data at December 31 Common shares outstanding (thousands) Number of stockholders of record RESULTS OF OPERATIONS Years Ended December 31, (Millions of dollars, except EPS) Income (loss) from continuing operations before income taxes $ Net loss $ Diluted EPS Loss from continuing operations $ Diluted EPS Loss from discontinued operations $ Diluted EPS (Millions of dollars) Exploration and production – continuing operations United States $ Canada Malaysia Other Total exploration and production – continuing operations Corporate and other Loss from continuing operations Loss from discontinued operations Net loss $ (Millions of dollars) 2017 2016 2015 United States – Oil and gas liquids $ – Natural gas Canada – Conventional oil and gas liquids – Synthetic oil – – Natural gas Malaysia – Oil and gas liquids – Natural gas Total oil and gas revenues $ The following 2017 2016 2015 Net crude oil and condensate produced – barrels per day United States – Eagle Ford Shale Gulf of Mexico Canada – onshore offshore heavy1 synthetic1 – Malaysia1 – Sarawak Block K Total crude oil and condensate produced Net crude oil and condensate sold – barrels per day United States – Eagle Ford Shale Gulf of Mexico Canada – onshore offshore heavy1 synthetic1 – Malaysia1 – Sarawak Block K Total crude oil and condensate sold Net natural gas liquids produced – barrels per day United States – Eagle Ford Shale Gulf of Mexico Canada Malaysia1 – Sarawak Total net gas liquids produced Net natural gas liquids sold – barrels per day United States – Eagle Ford Shale Gulf of Mexico Canada Malaysia1 – Sarawak Total net natural gas liquids sold Net natural gas sold – thousands of cubic feet per day United States – Eagle Ford Shale Gulf of Mexico Canada Malaysia1 – Sarawak Block K Total natural gas sold Total net hydrocarbons produced – equivalent barrels per day2 Total net hydrocarbons sold – equivalent barrels per day2 Estimated net hydrocarbon reserves – million equivalent barrels2,3 2017 2016 2015 Weighted average sales prices Crude oil and condensate – dollars per barrel United States – Eagle Ford Shale $ Gulf of Mexico Canada 1 – onshore offshore heavy 2 synthetic 2 – Malaysia – Sarawak 3 Block K 3 Natural gas liquids – dollars per barrel United States – Eagle Ford Shale Gulf of Mexico Canada 1 Malaysia – Sarawak 3 Natural gas – dollars per thousand cubic feet United States – Eagle Ford Shale Gulf of Mexico Canada 1 Malaysia – Sarawak 3 Block K non-operated Placid Montney assets, as well as natural declines. Higher sales volumes at Tupper Montney were the result of new wells coming online in 2023, improved well performance, and lower royalty rates. (Millions of dollars) Lease operating expense $ Severance and ad valorem taxes Depreciation, depletion and amortization Total $ (Dollars per equivalent barrel) United States – Eagle Ford Shale Lease operating expense $ Severance and ad valorem taxes Depreciation, depletion and amortization (DD&A) expense United States – Gulf of Mexico Lease operating expense Severance and ad valorem taxes – DD&A expense Canada – Onshore Lease operating expense Severance and ad valorem taxes DD&A expense Canada – Offshore Lease operating expense DD&A expense Malaysia – Sarawak Lease operating expense DD&A expense Malaysia – Block K Lease operating expense DD&A expense Total oil and gas operations Lease operating expense Severance and ad valorem taxes DD&A expense Total oil and gas operations – excluding synthetic oil operations Lease operating expense Severance and ad valorem taxes DD&A expense Depreciation, depletion and amortization expense (Millions of dollars) 2017 2016 2015 Dry holes $ Geological and geophysical Other Undeveloped lease amortization Total exploration expenses $ the periods presented. Company had no outstanding borrowings under the RCF. is one option to transition from higher carbon emitting fuels. amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs and future inflation levels. 2023 or 2022. Accounting for retirement and postretirement benefit plans – Murphy Contractual obligations and guarantees– The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure Amount of Obligations (Millions of dollars) Total 2018 2019-2020 2021-2022 After 2022 Debt including current maturities $ Operating and other leases Capital expenditures, drilling rigs and other Other long-term liabilities, including debt Total $ 2023. operating cash flows. differences between budgeted and December 31, 2023, the Company has $450 million remaining available to repurchase. Board. Page No. Exhibit Incorporated by Reference to Exhibit 3.1 Exhibit 3.2 Exhibit 4.2 Exhibit 4.1 Exhibit 4.1 Exhibit Exhibit Exhibit 10.1 to Form 10-K filed February 27, 2023 *23.3 Inline XBRL Instance Document Inline XBRL Taxonomy Extension Schema Document Inline XBRL Taxonomy Extension Calculation Linkbase Document Inline XBRL Taxonomy Extension Definition Linkbase Document Inline XBRL Taxonomy Extension Labels Linkbase Document Inline XBRL Taxonomy Extension Presentation Linkbase By /s/ ROGER W. JENKINS Date: February 23, Roger W. Jenkins, /s/ CLAIBORNE P. DEMING /s/ Claiborne P. Deming, Chairman and Director /s/ ROGER W. JENKINS /s/ /s/ /s/ JEFFREY W. NOLAN Jeffrey W. Nolan, Director /s/ /s/ LAURA A. SUGG Laura A. Sugg, Director Vaughan 62. 2023. December 31 (Thousands of dollars) 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 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 $ Years Ended December 31 (Thousands of dollars except per share amounts) 2017 2016 1 2015 1 Revenues Sales and other operating revenues $ Gain on sale of assets Total revenues Costs and Expenses Lease operating expenses Severance and ad valorem taxes Exploration expenses, including undeveloped Selling and general expenses Depreciation, depletion and amortization Impairment of assets – Redetermination expense – Accretion of asset retirement obligations Other expense 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 Loss from discontinued operations, net of income taxes NET LOSS $ LOSS PER COMMON SHARE – BASIC Continuing operations $ Discontinued operations – Net loss $ LOSS PER COMMON SHARE – DILUTED Continuing operations $ Discontinued operations – Net loss $ Cash dividends per Common share Average Common shares outstanding (thousands) Basic Diluted Years Ended December 31 (Thousands of dollars) 2017 2016 2015 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 Other comprehensive income (loss) COMPREHENSIVE LOSS $ Years Ended December 31 (Thousands of dollars) 2017 2016 2015 Operating Activities Net loss $ Adjustments to reconcile net loss to net cash provided by 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 income tax expense (benefit) Pretax gains from disposition of assets Net (increase) decrease in noncash operating working capital Other operating activities, net Net cash provided by continuing operations activities Investing Activities Property additions and dry hole costs Proceeds from sales of property, plant and equipment Purchase of investment securities 1 Proceeds from maturity of investment securities 1 Other investing activities, net – Net cash provided (required) by investing activities Financing Activities Borrowings of debt Repayments of debt Capital lease obligation payments Purchase of treasury stock – – 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 – Investing activities – – Changes in cash included in current assets held for sale – Net increase (decrease) in cash and cash equivalents – Effect of exchange rate changes on cash and cash equivalents Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ current period presentation. Years Ended December 31 (Thousands of dollars) 2017 2016 2015 Cumulative Preferred Stock – par $100, authorized $ – – – Common Stock – par $1.00, authorized 450,000,000 shares at Balance at beginning of year Exercise of stock options – – Balance at end of period Capital in Excess of Par Value Balance at beginning of year Exercise of stock options, including income tax benefits – Restricted stock transactions and other Stock-based compensation Other Balance at end of period Retained Earnings Balance at beginning of year Net loss for the year Cash dividends – $1.00 per share in 2017, $1.20 per share in 2016 Balance at end of period Accumulated Other Comprehensive Loss Balance at beginning of year Foreign currency translation gains (losses), net of income taxes Retirement and postretirement benefit plans, net of income taxes Deferred loss on interest rate hedge reclassified to interest expense, Balance at end of year Treasury Stock Balance at beginning of year Purchase of treasury shares – – Sale of stock under employee stock purchase plans Awarded restricted stock Balance at end of year – 22,482,851 shares of Common Stock in 2017, Total Stockholders’ Equity $ Polices estimates. asset disposals or retirements are included in net income/(loss) as a component of revenues. ACCOUNTS RECEIVABLE – At December 31, See 2022. See specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis, whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in See See See Note B – New Accounting Principles and Recent Accounting Pronouncements standard. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES Revenue from Contracts with Customers (Continued) (Thousands of dollars) 2017 2016 Current assets Cash $ Accounts receivable Other – – Total current assets held for sale $ Current liabilities Accounts payable $ Accrued compensation and severance – – Refinery decommissioning cost Total current liabilities associated with assets held for sale $ Non-current liabilities Asset retirement obligation – Seal asset $ – MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES (Thousands of dollars) 2017 2016 2015 Revenues $ Loss from operations before income taxes $ Loss on sale before income taxes – – Total loss from discontinued operations before taxes Income tax expense – – Loss from discontinued operations $ December 31, 2017 2016 (Thousands of dollars) Unsold crude oil $ Materials and supplies $ December 31, 2017 December 31, 2016 (Thousands of dollars) Cost Net Cost Net Exploration and production1 $ 2 2 Corporate and other $ 1 Includes unproved mineral rights as follows: $ In closing adjustments. December 31, (Thousands of dollars) 2017 2016 2015 Gulf of Mexico $ – – Canada – Malaysia – – $ – Exploratory Wells (Thousands of dollars) 2017 2016 2015 Beginning balance at January 1 $ Additions pending the determination of proved reserves Reclassifications to proved properties based on the – – Capitalized exploratory well costs charged to expense – Ending balance at December 31 $ Mexico. 2017 2016 2015 (Thousands of dollars) Amount No. of No. of Amount No. of No. of Amount No. of No. of Aging of capitalized well Zero to one year $ $ $ One to two years – – – Two to three years – – – – Three years or more – – $ $ $ 15, 2024. December 31, (Thousands of dollars) Notes payable 3.50% notes, due December 2017 $ - 4.00% notes, due June 2022 4.45% notes, due December 20221 6.875% notes, due August 2024 5.75% notes, due August 2025 - 7.05% notes, due May 2029 5.875% notes, due December 20421 Total notes payable Unamortized debt issuance cost and discount on notes payable Total notes payable, net of unamortized discount Capitalized lease obligation, due through March 2029 Total debt including current maturities Current maturities Total long-term debt $ Note (Thousands of dollars) 2017 2016 Balance at beginning of year $ Accretion expense Liabilities incurred Revisions of previous estimates Liabilities settled Liabilities assumed by purchaser of oil and gas assets Changes due to translation of foreign currencies Balance at end of year Liabilities reported as held for sale at end of year1 – Current portion of liability at end of year2 Noncurrent portion of liability at end of year $ Sheets. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES (Thousands of dollars) 2017 2016 2015 Income (loss) from continuing operations before income taxes United States $ Foreign Total $ Income tax expense (benefit) Federal – Current $ – – – Deferred Total Federal State Foreign – Current – Deferred Total Foreign Total $ (Thousands of dollars) 2017 2016 2015 Income tax expense (benefit) based on the U.S. statutory tax rate $ Revaluation of deferred tax (US tax reform) – – Deferred tax effect of deemed repatriation of foreign invested – – Deferred tax effect on Canadian earnings no longer indefinitely – – Foreign income (loss) subject to foreign tax rates different than State income taxes, net of federal benefit U.S. tax benefit on certain foreign upstream investments Deferred tax on distribution of foreign earnings – – Tax effects on sale of Canadian assets – – Tax effects on sale of Malaysian assets – Increase in deferred tax asset valuation allowance related Other, net Total $ MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES (Thousands of dollars) 2017 2016 Deferred tax assets Property and leasehold costs $ Liabilities for dismantlements Postretirement and other employee benefits Alternative minimum tax Foreign tax credit carryforwards U. S. net operating loss Other deferred tax assets Total gross deferred tax assets Less valuation allowance Net deferred tax assets Deferred tax liabilities Deferred tax on undistributed foreign earnings – Accumulated depreciation, depletion and amortization Other deferred tax liabilities Total gross deferred tax liabilities Net deferred tax assets $ deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions The Company Company. (Thousands of dollars) 2017 2016 2015 Balance at January 1 $ Additions for tax positions related to current year Settlements due to lapse of time – – Foreign currency translation effect Balance at December 31 $ 2024. rights to income tax receivables relating to Malaysia for the years prior to 2019. The (Thousands of dollars) 2017 2016 2015 Compensation charged against income (loss) before income tax benefit $ Related income tax benefit recognized in income 2017 2016 2015 Fair value per option grant $7.96 $5.03 $10.97 – $11.08 Assumptions Dividend yield 3.60% 4.00% 2.40% – 2.50% Expected volatility 41.00% 45.00% 29.00% – 30.00% Risk-free interest rate 1.97% 1.32% 1.34% – 1.60% Expected life 5.30 yrs. 5.20 yrs. 5.30 yrs. Number of Average Outstanding at December 31, 2014 $ Granted at FMV Exercised Forfeited Outstanding at December 31, 2015 Granted at FMV Exercised – – Forfeited Outstanding at December 31, 2016 Granted at FMV Exercised – – Forfeited Outstanding at December 31, 2017 Exercisable at December 31, 2014 $ Exercisable at December 31, 2015 Exercisable at December 31, 2016 Exercisable at December 31, 2017 Options Outstanding Options Exercisable Range of Exercise No. of Avg. Life Aggregate No. of Avg. Life Aggregate $17.00 to $30.00 5.5 $ – – $ – $31.00 to $50.00 3.9 – 3.8 – $51.00 to $65.00 1.6 – 1.6 – 3.0 $ 1.9 $ – PERFORMANCE-BASED RESTRICTED STOCK UNITS – (Number of share units) 2017 2016 2015 Outstanding at beginning of year Granted Awarded Forfeited Outstanding at end of year The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period. The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds, and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 2017 2016 2015 Fair value per share at grant date $24.10 – $28.28 $12.21 – $16.34 $44.03 – $48.12 Assumptions Expected volatility 47.00% 33.00% 26.00% Risk-free interest rate 1.46% 0.93% 0.85% Stock beta 1.058 0.863 0.813 Expected life 3.0 yrs. 3.0 yrs. 3.0 yrs. (Number of share units) 2017 2016 2015 Outstanding at beginning of year Granted Vested and issued Forfeited Outstanding at end of year MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CRSUs. 2021. The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, Pension Other (Thousands of dollars) 2017 2016 2017 2016 Change in benefit obligation Obligation at January 1 $ Service cost Interest cost Participant contributions – – Actuarial loss (gain) Medicare Part D subsidy – – Exchange rate changes Benefits paid Curtailments – – Other – – – Obligation at December 31 Change in plan assets Fair value of plan assets at January 1 – – Actual return on plan assets – – Employer contributions Participant contributions – – Medicare Part D subsidy – – Exchange rate changes – – Benefits paid Other – – Fair value of plan assets at December 31 – – Funded status and amounts recognized in the Deferred charges and other assets – – Other accrued liabilities Deferred credits and other liabilities Funded status and net plan liability recognized $ 1At December 31, (Thousands of dollars) Pension Other Net actuarial loss $ Prior service (cost) credit $ (Thousands of dollars) Pension Other Net actuarial loss $ – Prior service (cost) credit $ The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets. Projected Accumulated Fair Value (Thousands of dollars) 2017 2016 2017 2016 2017 2016 Funded qualified plans where $ Unfunded nonqualified and directors' – – Unfunded other postretirement plans – – The table that follows provides the components of net periodic benefit expense for each of the three years Pension Benefits Other (Thousands of dollars) 2017 2016 2015 2017 2016 2015 Service cost $ Interest cost Expected return on plan assets – – – Amortization of prior service Amortization of transitional – – – – – Recognized actuarial loss – Termination benefits expense – – – – – Curtailment expense – – – Net periodic benefit expense $ Pension Other (Thousands of dollars) 2017 2016 2017 2016 Benefit obligation at December 31 $ Fair value of plan assets at December 31 – – Net plan liabilities recognized Net periodic benefit expense (benefit) Benefit Obligations Net Periodic Benefit Expense Pension Other Pension Other December 31 December 31 Year Year 2017 2016 2017 2016 2017 2016 2017 2016 Discount rate Expected return on plan assets – – – – Rate of compensation increase – – – – The plan’s cash balance interest accumulation rate is the greater of the annual yield on 10-year treasury constant maturities or 1.89%. (Thousands of dollars) Pension Other 2018 $ 2019 2020 2021 2022 2023-2027 For purposes of measuring postretirement benefit obligations at December 31, (Thousands of dollars) 1% Increase 1% Decrease Effect on total service and interest cost components of net periodic postretirement $ Effect on the health care component of the accumulated postretirement benefit During MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES December 31, 2017 2016 Equity securities % % Fixed income securities Cash equivalents % % The Company’s weighted average expected return on plan assets was Fair Value Measurements Using (Thousands of dollars) Fair Value at Quoted Prices Significant Significant Domestic Plans Equity securities: U.S. core equity $ – – U.S. small/midcap – – Hedged funds and other – International commingled – – Emerging market commingled – – Fixed income securities: U.S. fixed income – – International commingled – – Emerging market mutual fund – – Cash and equivalents – – Total Domestic Plans Foreign Plans Equity securities funds – – Fixed income securities funds – – Diversified pooled fund – – Cash and equivalents – – Total Foreign Plans – – Total $ Fair Value Measurements Using (Thousands of dollars) Fair Value at Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Domestic Plans Equity securities: U.S. core equity $ – – U.S. small/midcap – – Hedged funds and other – International commingled – – Emerging market commingled – – Fixed income securities: U.S. fixed income – – International commingled – – Emerging market mutual fund – – Cash and equivalents – – Total Domestic Plans Foreign Plans Equity securities funds – – Fixed income securities funds – – Diversified pooled fund – – Cash and equivalents – – Total Foreign Plans – – Total $ The definition of levels within the fair value hierarchy in the tables above is included in Note O. Hedged Funds and Other Total at December 31, Actual return on plan assets: Relating to assets held at the reporting date Purchases, sales and settlements Total at December 31, Actual return on plan assets: Relating to assets held at the reporting date Total at December 31, 2021. Company redeemed all of the remaining notes due 2022, which were associated with the interest rate derivative contracts and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to “Interest expense, net” in the Consolidated Statement of Operations. 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 purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts required payments by the Company if the NYMEX average closing price was above the ceiling price or payments to the Company if the NYMEX average closing price was below the floor price. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES December 31, 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 payable $ Gain (Loss) (Thousands of dollars) Year Ended December 31, Type of Derivative Contract Statement of Operations Locations 2017 2016 Commodity Sales and other operating revenues $ $ Foreign exchange Interest and other income (loss) – $ $ (Weighted-average shares) 2017 2016 2015 Basic method Dilutive stock options 1 – – – Diluted method 2017 2016 2015 Antidilutive stock options excluded from diluted shares Weighted average price of these options Note 2021. (Thousands of dollars) 2017 2016 2015 Accounts receivable $ Inventories Prepaid expenses Deferred income tax assets – – Accounts payable and accrued liabilities Current income tax liabilities Net (increase) decrease in noncash operating working capital $ Supplementary disclosures (including discontinued operations): Cash income taxes paid, net of refunds $ Interest paid, net of amounts capitalized of $4,488 in 2017, Noncash investing activities, related to continuing operations: Asset retirement costs capitalized $ Decrease in capital expenditure accrual (Thousands of dollars) Foreign Retirement and Deferred Total Balance at December 31, 2015 $ 2016 components of other comprehensive income (loss): Before reclassifications to income – Reclassifications to income – 1 2 Net other comprehensive income 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 (loss) Balance at December 31, 2017 $ The fair value measurements for these assets and liabilities December 31, 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 – – – – – – $ – – 2022. certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal. At December 31, 2017 2016 (Thousands of dollars) Carrying Fair Carrying Fair Financial assets (liabilities): Canadian government securities with maturities $ - - Current and long-term debt Fair Values – Nonrecurring Year Ended December 31, 2016 Total Net Book Pretax Value (Noncash) Fair Value Prior to Impairment (Thousands of dollars) Level 1 Level 2 Level 3 Impairment Expense Assets: Impaired proved properties Western Canada $ – – $ – – 2021. $4.0 million for Other Foreign. financial condition. (Number of shares outstanding) 2017 2016 2015 Beginning of year Stock options exercised 1 – – Restricted stock awards 1 Employee stock purchase and thrift plans Treasury shares purchased – – End of year Segment Information Exploration and Production (Millions of dollars) United Canada1 Malaysia Other Total Year ended December 31, 2017 Segment income (loss) $ Revenues from external customers – Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) Significant noncash charges (credits) Depreciation, depletion and amortization Accretion of asset retirement obligations – Amortization of undeveloped leases – – Deferred and noncurrent income taxes Additions to property, plant, equipment Total assets at year-end Year ended December 31, 2016 Segment income (loss) $ Revenues from external customers Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) Significant noncash charges (credits) Depreciation, depletion and amortization Accretion of asset retirement obligations – Amortization of undeveloped leases – Impairment of assets – – – Deferred and noncurrent income taxes Additions to property, plant, equipment Total assets at year-end Year ended December 31, 2015 Segment loss $ Revenues from external customers – Interest income – – – – – Interest expense, net of capitalization – – – – – Income tax expense (benefit) Significant noncash charges (credits) Depreciation, depletion and amortization Accretion of asset retirement obligations – Amortization of undeveloped leases – Impairment of assets – Deferred and noncurrent income taxes Additions to property, plant, equipment Total assets at year-end Geographic Information Certain Long-Lived Assets at December 31 (Millions of dollars) United Canada Malaysia United Other Total 2017 $ – 2016 – 2015 – MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES Segment Information — Continued (Millions of dollars) Corporate Discontinued Consolidated Year ended December 31, 2017 Segment income (loss) $ Revenues from external customers – Interest income – Interest expense, net of capitalization – Income tax expense (benefit) – Significant noncash charges (credits) Depreciation, depletion and amortization – Accretion of asset retirement obligations – – Amortization of undeveloped leases – – Deferred and noncurrent income taxes – Additions to property, plant, equipment – Total assets at year-end Year ended December 31, 2016 Segment income (loss) $ Revenues from external customers – Interest income – Interest expense, net of capitalization – Income tax expense (benefit) – Significant noncash charges (credits) Depreciation, depletion and amortization – Accretion of asset retirement obligations – – Amortization of undeveloped leases – – Impairment of assets – – Deferred and noncurrent income taxes – Additions to property, plant, equipment – Total assets at year-end Year ended December 31, 2015 Segment loss $ Revenues from external customers – Interest income – Interest expense, net of capitalization – Income tax expense (benefit) – Significant noncash charges (credits) Depreciation, depletion and amortization – Accretion of asset retirement obligations – – Amortization of undeveloped leases – – Impairment of assets – – Deferred and noncurrent income taxes – Additions to property, plant, equipment – Total assets at year-end Geographic Information Revenues from External Customers for the Year (Millions of dollars) United Canada Malaysia Other Total 2017 $ – 2016 2015 – for Crude & Crude Oil Synthetic (Millions of barrels) Total Total United Canada Malaysia Canada Proved developed and December 31, 2014 Revisions of previous estimates Improved recovery – – – Extensions and discoveries – – – Sales of properties – – – Production December 31, 2015 Revisions of previous estimates – Extensions and discoveries – – Purchases of properties – – – Sales of properties – Production December 31, 2016 Revisions of previous estimates – Improved recovery – – – Extensions and discoveries – – Purchases of properties – – – Production – December 31, 2017 – Proved developed crude December 31, 2014 December 31, 2015 December 31, 2016 – December 31, 2017 – Proved undeveloped crude December 31, 2014 – December 31, 2015 – December 31, 2016 – December 31, 2017 – for at the Gulf of Mexico and Eagle Ford Shale. the Gulf of Mexico. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES for (Millions of barrels) Total United Canada Malaysia Proved developed and undeveloped NGL reserves: December 31, 2014 Revisions of previous estimates Extensions and discoveries – – Sales of properties – – Production – December 31, 2015 Revisions of previous estimates Extensions and discoveries – Purchases of properties – – Production December 31, 2016 Revisions of previous estimates Extensions and discoveries – Purchases of properties – – Production December 31, 2017 Proved developed NGL reserves: December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2017 Proved undeveloped NGL reserves: December 31, 2014 – December 31, 2015 – December 31, 2016 – December 31, 2017 – for as well as in Canada at Kaybob Duvernay. Gulf of Mexico. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES (Billions of cubic feet) Total United Canada Malaysia Proved developed and undeveloped December 31, 2014 Revisions of previous estimates Improved recovery – – Extensions and discoveries – Sales of properties – – Production December 31, 2015 Revisions of previous estimates Extensions and discoveries Purchases of properties – – Sales of properties – Production December 31, 2016 Revisions of previous estimates Extensions and discoveries Purchases of properties – – Production December 31, 2017 Proved developed natural gas reserves: December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2017 Proved undeveloped natural gas reserves: December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2017 Montney. higher commodity prices at Tupper Montney. MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES (Millions of dollars) United Canada Malaysia Other Total Year ended December 31, 2017 Property acquisition costs Unproved $ – – Proved – – – Total acquisition costs – – Exploration costs 1 Development costs 1 Total costs incurred Charged to expense Dry hole expense – Geophysical and other costs Total charged to expense Property additions $ Year ended December 31, 2016 Property acquisition costs Unproved $ – – – Proved – – – Total acquisition costs – – Exploration costs 1 Development costs 1 Total costs incurred Charged to expense Dry hole expense – Geophysical and other costs Total charged to expense Property additions $ Year ended December 31, 2015 Property acquisition costs Unproved $ – – Proved – – – – – Total acquisition costs – – – Exploration costs 1 Development costs 1 Total costs incurred Charged to expense Dry hole expense – Geophysical and other costs Total charged to expense Property additions $ 2017 Exploration costs $ – – – – – Development costs – $ – 2016 Exploration costs $ – – – – – Development costs – $ – 2015 Exploration costs $ – – – – – Development costs – $ – Canada United Conven- (Millions of dollars) States tional Synthetic Malaysia Other Total Year ended December 31, 2017 Revenues Crude oil and natural gas liquids sales $ – – Natural gas sales – – Total oil and gas revenues – – Other operating revenues – – Total revenues – – Costs and expenses Lease operating expenses – – Severance and ad valorem taxes – – – Exploration costs charged to expense – Undeveloped lease amortization – – – Depreciation, depletion and amortization – Accretion of asset retirement obligations – – Redetermination expense – – – – Selling and general expenses – Other expenses – – Total costs and expenses – Results of operations before taxes – Income tax expense (benefit) – Results of operations $ – Year ended December 31, 2016 Revenues Crude oil and natural gas liquids sales $ – Natural gas sales – – Total oil and gas revenues – Other operating revenues Total revenues Costs and expenses Lease operating expenses – Severance and ad valorem taxes – – Exploration costs charged to expense – Undeveloped lease amortization – – Depreciation, depletion and amortization Accretion of asset retirement obligations – Impairment of assets – – – – Redetermination expense – – – – Selling and general expenses Other expenses (benefits) – Total costs and expenses Results of operations before taxes Income tax expense (benefit) Results of operations $ Canada United Conven- (Millions of dollars) States tional Synthetic Malaysia Other Total Year ended December 31, 2015 Revenues Crude oil and natural gas liquids sales $ – Natural gas sales – – Total oil and gas revenues – Other operating revenues – Total revenues – Costs and expenses Lease operating expenses – Severance and ad valorem taxes – – Exploration costs charged to expense – Undeveloped lease amortization – – Depreciation, depletion and amortization Accretion of asset retirement obligations – Impairment of assets – – Selling and general expenses Other expenses – Total costs and expenses Results of operations before taxes Income tax expense (benefit) Results of operations $ (Millions of dollars) United Canada Malaysia Total December 31, 2017 Future cash inflows $ Future development costs Future production costs Future income taxes Future net cash flows 10% annual discount for estimated timing Standardized measure of discounted $ December 31, 2016 Future cash inflows $ Future development costs Future production costs Future income taxes Future net cash flows 10% annual discount for estimated timing Standardized measure of discounted $ December 31, 2015 Future cash inflows $ Future development costs Future production costs Future income taxes Future net cash flows 10% annual discount for estimated timing Standardized measure of discounted $ 1 Includes noncontrolling interest in MP GOM. (Millions of dollars) 2017 2016 2015 Net changes in prices and production costs $ Net changes in development costs Sales and transfers of oil and gas produced, net of production costs Net change due to extensions and discoveries Net change due to purchases and sales of proved reserves Development costs incurred Accretion of discount Revisions of previous quantity estimates Net change in income taxes Net increase (decrease) Standardized measure at January 1 Standardized measure at December 31 $ (Millions of dollars) United Canada Malaysia Other Total December 31, 2017 Unproved oil and gas properties $ Proved oil and gas properties – Gross capitalized costs Accumulated depreciation, Unproved oil and gas properties – Proved oil and gas properties – Net capitalized costs $ December 31, 2016 Unproved oil and gas properties $ Proved oil and gas properties – Gross capitalized costs Accumulated depreciation, Unproved oil and gas properties – Proved oil and gas properties – Net capitalized costs $ (Millions of dollars except per share amounts) First Second Third Fourth Year Year ended December 31, 2017 Sales and other operating revenues $ Income (loss) from continuing operations before Income (loss) from continuing operations Net income (loss) Income (loss) from continuing operations per Basic Diluted Net income (loss) per Common share Basic Diluted Cash dividend per Common share Market price of Common Stock 1 High Low Year ended December 31, 2016 Sales and other operating revenues $ Loss from continuing operations before Income (loss) from continuing operations Net income (loss) Income from continuing operations per Basic Diluted Net income (loss) per Common share Basic Diluted Cash dividend per Common share Market price of Common Stock 1 High Low (Millions of dollars) Balance at Charged Deductions Other 1 Balance at 2017 Deducted from asset accounts: Allowance for doubtful accounts $ – – – Deferred tax asset valuation allowance – 2016 Deducted from asset accounts: Allowance for doubtful accounts $ – – – Deferred tax asset valuation allowance – 2015 Deducted from asset accounts: Allowance for doubtful accounts $ – – – Deferred tax asset valuation allowance – oil and natural gas exploration and production operations, including synthetic oil entityIf 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2017)2023) – $4,189,400,296.Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 20182024 was 172,572,873.Documents incorporated by reference:Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 9, 2018 have been incorporated by reference in Part III herein.Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 08, 2024 have been incorporated by reference in Part III herein. MURPHY OIL CORPORATION2017TABLE OF CONTENTSPage Number Page NumberPART IItem 1.1 13 20 20 22 22 22 24 25 50 50 50 50 50 Item 9C. PART III51 51 51 51 51 52 56 iiItem 1. BUSINESSMurphy Oil Corporation is a worldwideglobal oil and gas exploration and production company.company, with both onshore and offshore operations and properties. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation,Corporation. In 2013, the U.S. downstream business was separated from Murphy Oil Corporation’s oil and was reorganized in 1983 to operate primarily as a holding company of its various businesses.gas exploration and production business. For reporting purposes, Murphy’s exploration and production activities are subdivided into fourthree geographic segments, including the United States, Canada Malaysia and all other countries. Additionally, the Corporate activities includesegment includes interest income, interest expense, foreign exchange effects, the impact of the Tax Cuts and Jobs Act (2017 Tax Act)corporate risk management activities and administrative costs not allocated to the exploration and production segments. The Company’s corporate headquarters are located in El Dorado, Arkansas.The Company has transitioned from an integrated oil company to an enterprise entirely focused on oil and gas exploration and production activities. The Company completed the saleHouston, Texas.As part of the remaining downstream assets inCompany’s underlying operations, the United Kingdom (U.K.) during 2015 after sellingCompany is continually monitoring its U.K. retail marketing assets during 2014.At December 31, 2017, Murphy had 1,128 employees. In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 2432 through 41, 7145, 74 through 73, 10476, 77 through 11578, 98 through 100, and 117103 through 118 of this Form 10-K report.Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Website at www.murphyoilcorp.com.Exploration and ProductionThe Company explores for and produces crude oil, natural gas and natural gas liquids worldwide. The Company’s explorationprimarily in the U.S. and production management team directs the Company’s worldwide explorationCanada and production activities. This business maintains upstream operating officesexplores for crude oil, natural gas and natural gas liquids in several locations around the world, with the most significant of these including Houston in Texas, Calgary in Alberta, and Kuala Lumpur in Malaysia.During 2017,2023, Murphy’s principal exploration and production activities were conducted in the United States by wholly ownedwholly-owned Murphy Exploration & Production Company – USA (Murphy Expro USA), and its subsidiaries, in Malaysia,Canada by wholly-owned Murphy Oil Company Ltd. and its subsidiaries and in Australia, Brazil, Brunei, Côte d’Ivoire, Mexico and Vietnam by wholly ownedwholly-owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries, and in Western Canada and offshore Eastern Canada by wholly-owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries. Murphy’s hydrocarbonoperations and production in 2017 was2023 were in the United States, Canada and Malaysia.Unless otherwise indicated, all references to the Company’s offshore U.S. and total oil, natural gas liquids and natural gas production and sales volumes and proved crude oil, natural gas liquids and natural gas reserves are net to the Company’s working interest excluding applicable royalties. Also, unless otherwise indicated, references to oil throughout this document could include crude oil, condensate and natural gas liquids where applicable volumes include a combinationnoncontrolling interest in MP Gulf of these products.Total worldwide crude oil and condensate production in 2017 averaged 90,431 barrels per day, a decrease of 13% compared to 2016. The decrease in 2017 was primarily due to the Syncrude divestiture in mid-2016, lower production from Seal as a result of the divesture in January 2017 and lower production in Malaysia resulting from normal decline. Excluding Syncrude and Seal, crude oil and condensate production averaged 90,281 barrels per day in 2017 and 95,998 barrels per day in 2016. Natural gas liquids produced in 2017 averaged 9,151 barrels per day, in line with 2016. The Company’s worldwide sales volume of natural gas averaged 384 million cubic feet (MMCF) per day in 2017, an increase of 1% from 2016 levels. The increase in natural gas sales volume in 2017 was primarily attributable to higher volumes at Canada from development of the Tupper, Kaybob & Placid assets, partially offset by lower gas volumes in the United States and Malaysia. Mexico, LLC (MP GOM; see further details below).Murphy’s worldwide 20172023 production on a1163,536 barrels per day, a decrease of 7% compared to 2016.Total production in 2018 is currently expected to average between 166,000 and 170,000192,640 barrels of oil equivalent per day, (BOED).For further details on business execution, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” starting on page 32. For further details on 2023 production and sales volume see pages 35 to 36.United StatesIn the United States, Murphy primarily has production ofproduces crude oil, natural gas liquids and natural gas primarily from fields in the Gulf of Mexico and in the Eagle Ford Shale area of South Texas and in the deepwater Gulf of Mexico.Texas. The Company produced approximately 54,000108,084 barrels of crude oil and natural gas liquids per day and approximately 4596 MMCF of natural gas per day in the U.S. in 2017.2023. These amounts represented 54%94.0% of the Company’s total worldwide oil and natural gas liquids and 12%20.6% of worldwide natural gas production volumes.1OffshoreThe Company holds rights to approximately 135600 thousand gross acres in the Gulf of Mexico. During 2023, approximately 73% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico, of which approximately 90% was derived from ten fields, including St. Malo, Samurai, Khaleesi, Mormont, Cascade and Chinook, Kodiak, Lucius, Neidermeyer, Marmalard and Front Runner. Total average daily production in the Gulf of Mexico in 2023 was 79,397 barrels of crude oil and natural gas liquids and 70 MMCF of natural gas. At December 31, 2023, Murphy had total proved reserves for Gulf of Mexico fields of 132.3 million barrels of oil and natural gas liquids and 100.7 billion cubic feet of natural gas. OnshoreThe Company holds rights to approximately 133 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and natural gas play. During 2023, approximately 27% of total U.S. hydrocarbon production was produced in the Eagle Ford Shale. Total 20172023 production in the Eagle Ford Shale area was 41,50028,641 barrels of oil and liquids per day and approximately 3325.7 MMCF per day of natural gas. On a barrel of oil equivalent basis, Eagle Ford production accounted for 76% of total U.S. production volumes in 2017. In 2018, production for the U.S. Onshore business is forecast to be lower and average approximately 40,000 barrels of oil and gas liquids per day and 29 MMCF of natural gas per day. At December 31, 2017,2023, the Company’s proved reserves for the U.S. Onshore business totaled 185.3130 million barrels of crude oil, 40.2 million barrels of natural gas liquids and 189.2192.4 billion cubic feet of natural gas.During 2017, approximately 24% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico. Approximately 87% of Gulf of Mexico production in 2017 was derived from five fields, including Dalmatian, Medusa, Kodiak, Front Runner and Thunder Hawk. The Company holds a 70% operated working interest in Dalmatian in DeSoto Canyon Blocks 4 and 134, a 60% operated interest in Medusa in Mississippi Canyon Blocks 538/582, a 29.1% non-operated interest in Kodiak in Mississippi Canyon Blocks 727/771, and 62.5% operated working interests in the Front Runner field in Green Canyon Blocks 338/339 and the Thunder Hawk field in Mississippi Canyon Block 734. Total daily production in the Gulf of Mexico in 2017 was 12,400 barrels of liquids and approximately 12 MMCF of natural gas. Production in the Gulf of Mexico in 2018 is expected to total approximately 13,500 barrels of oil and gas liquids per day and 12 MMCF of natural gas per day. At December 31, 2017, Murphy had total proved reserves for Gulf of Mexico fields of 42.2 million barrels of oil and gas liquids and 34.1 billion cubic feet of natural gas. Total U.S. proved reserves at December 31, 2017 were 224.7 million barrels of crude oil, 43.0 million barrels of natural gas liquids, and 223.3 billion cubic feet of natural gas.In Canada, the Company holds one wholly-owned natural gas area (Tupper) in the Western Canadian Sedimentary Basin (WCSB), working interests in theTupper Montney (100% owned), Kaybob Duvernay and liquids rich Placid Montney lands(operated) and two non-operated offshore assets – the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.The During 2023 the Company sold a portion of its working interest in Kaybob Duvernay and our entire 30% non-operated working interest in Placid Montney.OnshoreMurphy has 110approximately 139 thousand gross acres of Tupper Montney mineral rights located in northeast British Columbia. In 2016,addition, the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area. Total cash consideration received by Murphy upon closing of the transaction was $414.1 million. Connected with this sale, the Company entered into a commitment for natural gas processing capacity for minimum monthly payments through 2035. In 2016, the Company acquiredholds a 70% operated working interest in Kaybob Duvernay lands and a 30% non-operated working interest in liquids rich Placid Montney lands in Alberta.In the fourth quarter 2016, the The Company entered into an agreement to sell its wholly-owned Seal field located in the Peace River oil sands areahas approximately 165 thousand gross acres of northwest Alberta. This sale was completed in January 2017 and the Company received net proceeds of $48.8 million. 20172023 in the WCSBOnshore Canada averaged 3,7003,618 barrels of oil and gas liquids and approximately 226370 MMCF of natural gas, and increase of 195% (excluding Seal and Syncrude divestitures) and 8% versus 2016, respectively. Oil and natural gas dailywhich included production for 2018 in Western Canada, is expected to average 6,500 barrels and approximately 262 MMCF, respectively. The expected increase in oil production in 2018 arises from continued drilling and development in the Kaybob Duvernay andour divested Placid Montney areas acquired in mid-2016. The expected2increase inof 274 barrels of liquids and 3 MMCF of natural gas volumes in 2018 is primarily the result of new wells brought on line in the Tupper area and additional capacity at the Tupper West processing facility of 17 MMCFD commencing in late 2017.gas. Total WCSBOnshore Canada proved liquids and natural gas reserves at December 31, 2017,2023, were approximately 36.316.4 million barrels and 1.22.2 trillion cubic feet, respectively.OffshoreThe Company holds a non-operated interest in approximately 133 thousand gross acres offshore Canada. Murphy has a 6.5% working interest in Hibernia while at Terra Nova the Company’sMain, a 4.3% working interest is 10.475%. in Hibernia South Extension and an 18% working interest in Terra Nova. Oil production in 20172023 was about 8,1002,780 barrels of oil per day for Hibernia.In 2023, the two offshore Canada fields. OilTerra Nova asset life extension project was completed and production for 2018 for offshore Canada is anticipated to be approximately 7,400 barrels per day.The decrease in anticipated 2018 oil production is primarily the result of a planned turnaround at Hibernia. Total proved oil reserves at December 31, 2017 for the two fields were approximately 20.9 million barrels.In June 2016, MOCL completed the sale of its 5% undivided interest in Syncrude Canada Ltd. (Syncrude) for net proceeds of $739.1 million.MalaysiaIn Malaysia, the Company has majority interests in nine separate production sharing contracts (PSCs). The Company serves as the operator of all these areas other than the unitized Kakap-Gumusut field. The PSCs cover approximately 2.67 million gross acres. In December 2014 and January 2015, the Company sold 30% of its interest in substantially all of its Malaysian oil and gas assets for net proceeds of approximately $1.88 billion.Murphy has a 59.5% interest in oil and natural gas discoveries in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. Approximately 13,500 barrels of oil and gas liquids per day were produced in 2017 at Blocks SK 309/311. Oil and gas liquids production in 2018 at fields in Blocks SK 309/311 (Sarawak) is anticipated to total about 12,500 barrels per day.The Company has a gas sales contract for the Sarawak area with Petronas, the Malaysian state-owned oil company, and has an ongoing multi-phase development plan for several natural gas discoveries on these blocks. The gas sales contract allows for gross sales volumes of 250 MMCF per day through September 2021, but allows the Company to deliver higher sales volumes as requested. Total net natural gas sales volume offshore Sarawak was about 105 MMCF per day during 2017. Sarawak net natural gas sales volumes are anticipated to be approximately 102-103 MMCF per day in 2018.Total proved reserves of liquids and natural gas at December 31, 2017 for Blocks SK 309/311 were 9.8 million barrels and approximately 129 billion cubic feet (BCF), respectively.In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the owners. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field.Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia the Company now has a 6.35% interest in the Kakap field in Block K Malaysia as of December 31, 2017. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15 million ($9.3 million after taxes) related to the Company’s revised working interest.The Siakap oil field was developed as a unitized area with the Petai field owned by others, and the combined development is operated by Murphy, with a tie-back to the Kikeh field with production beginning in 2014. Oil production at Block K averaged approximately 20,300 barrels per day during 2017. Oil production at Block K is anticipated to average approximately 17,700 barrels per day in 2018. The reduction in Block K Kikeh oil production in 2018 is primarily attributable to overall field decline and reduction in working interest at Kakap as described above.The Company has a Block K natural gas sales contract with Petronas that calls for gross sales volumes of up to 120 MMCF per day. Gas production in Block K will continue until the earlier of lack of available commercial quantities3of associated gas reserves or expiry of the Block K production sharing contract. Natural gas production in Block K in 2017 totaled 8 MMCF per day. Daily gas production in 2018 in Block K is expected to average about 5-6 MMCF per day. Total proved reserves booked in Block Krestarted at the end of 2017November. Production is expected to ramp up over the coming months. Total oil production in 2023 was 240 barrels of oil per day for Terra Nova.Total proved reserves for offshore Canada at December 31, 2023 were 42.4approximately 22.3 million barrels of crude oilliquids and about 24.314.8 billion cubic feet of natural gas.The Company also has an interest in deepwater Block H offshore Sabah. In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H. The Company followed up Rotan with several other nearby discoveries. Murphy’s interests in Block H range between 42% and 56%. Total gross acreage held by the Company at the end of 2017 in Block H was 679 thousand gross acres. In early 2014, Petronas and the Company sanctioned a Floating Liquefied Natural Gas (FLNG) project for Block H, and agreed terms for sales of natural gas to be produced with prices tied to an oil index. First production is currently expected at Block H in mid-2020. At December 31, 2017, total natural gas proved reserves for Block H were approximately 335.2 billion cubic feet.The Company had a 42% interest in a gas holding area covering approximately 1,854 gross acres in Block P. This interest expired in January 2018.In November 2017, the Company acquired a 59.5% working interest in Sarawak SK405B PSC. The block SK405B is approximately 2,305 square kilometers (890 square miles) and has water depths in the range from 10 to 50 meters (33 to 164 feet). Under the terms of the PSC, the Company will operate the block with a participating interest of 59.5%.In February 2016, the Company acquired a 40% working interest in Block Deepwater SK2A PSC, offshore Sarawak. The Company operates the block with a commitment to acquire and process new 3D seismic. The commitment was fulfilled during 2016. A decision to enter the next phase of the PSC, involving a one-well commitment, will be made in the future. This block includes 609 thousand gross acres.In February 2015, the Company acquired a 50% interest in Block SK 2C, offshore Sarawak. The Company operates the block that carried one well commitment during the one year initial exploration period. The exploration well was drilled in 2015, and the first exploration period was extended for a further eighteen months. In 2016, the Company elected not to enter the next exploration period. The block was relinquished with the exception of an application made for a gas holding area comprising the Paus gas and oil discovery. BrazilThe Company holds an 80% working interest in the gas holding area application, which is under consideration by government authorities.In May 2013, the Company acquired an interest in shallow-water Malaysia Block SK 314A. The PSC covered a three-year exploration period. The Company’s working interest in Block SK 314A is 59.5%. This block includes 488 thousand gross acres. The Company has a 70% carry of a 15% partner in this concession through the minimum work program. The first two exploration wells were drilled in 2015 and the third well in 2016. The Company has successfully secured an annexation of an open area in Sarawak to SK314A to complete the remaining fourth and fifth exploration commitment wells.AustraliaIn Australia, the Company holds six offshore exploration permits and serves as operator of four of them.In December 2017, Murphy signed a farm-in agreement to acquire a 40% non-operated interest in AC/P21 in the Vulcan Basin, offshore Western Australia. Acquisition of multiclient 3D seismic commenced over the permitted area in December 2017. The permit comprises approximately 165 thousand acres and expires in June 2019.In March 2015, Murphy was awarded the AC/P59 license, another acreage position in the Vulcan Basin. The block covers approximately 288 thousand gross acres. The exploration requires 3D seismic reprocessing, which was completed in 2016. The permit expires in 2021.In April 2014 and June 2014, Murphy was awarded licenses AC/P57 and AC/P58 in the Vulcan Basin. The blocks cover approximately 82 thousand and 692 thousand gross acres, respectively. These exploration permits require 3D seismic reprocessing and a gravity survey that were completed in 2017. The permits expire in 2020.The Company was awarded permit EPP43 in the Ceduna Basin, offshore South Australia, in October 2013. The Company operates and holds a 50% working interest in the concession covering approximately 4.08 million gross acres. The exploration permit has commitments for 2D and 3D seismic, which was completed in the first half of 2015 and processed in 2016. This permit expires in 2020.In November 2012, Murphy acquired a 20% non-operated working interest in permit WA-408-Pnine blocks in the Browse Basin. The permit comprised approximately 417 thousand gross acres. offshore regions of the Sergipe-Alagoas Basin (SEAL) in Brazil (SEAL-M-351, SEAL-M-428, SEAL-M-430, SEAL-M-501, SEAL-M-503, SEAM-M-505, SEAL-M-573, SEAL-M-575 and SEAL-M-637). Murphy drilled two wells in42013. The first well found hydrocarbon but was deemed commercially unsuccessful and was written off to expense. The second well was also unsuccessful, and costs were expensed in 2013. Although extended in 2016, the permit was released in 2017.The Company also acquired permit WA-481-P in the Perth Basin, offshore Western Australia, in August 2012. All commitments were fulfilled in 2015. In 2016, the Company’s working interest was sold to another company.In May 2012, Murphy was awarded permit WA-476-P in the Carnarvon Basin, offshore Western Australia. The Company formerly heldhas a 100% working interest in the permit which covers 177 thousand gross acres. The permit had a primary term work commitment consisting of seismic data purchase and geophysical studies. All primary term commitments were completed. This permit was released in 2017.The Company’s first permit in Australia was acquired in 2007. It consisted of a 40% interest in Block AC/P36three blocks in the Browse Basin. Murphy renewed the exploration permit for an additional five years,Potiguar Basin (POT-M-857, POT-M-863 and POT-M-865).Murphy’s total acreage position in that process relinquished 50%Brazil as of theDecember 31, 2023 is approximately 2.5 million gross acreage. In 2012, Murphy increased itsacres, offsetting several major discoveries. There are no well commitments.2BruneiThe Company has a working interest in the remaining acreage to 100% and subsequently farmed out a 50% working interest and operatorship. The license now covers 482 thousand gross acres and expires in 2019. The existing work commitment includes further geophysical work.BruneiIn late 2010, the Company entered into two production sharing agreements for properties offshore Brunei. The Company had a 5% working interestof 8.051% in Block CA-1 and a 30% working interestas of December 31, 2023.Oil production in Block CA-2. In 2015, the Company exercised a preemptive right that increased its working interest in Block CA-1 to 8.051%. The CA-1 and CA-2 blocks cover 1.44 million and 1.49 million gross acres, respectively. Four exploration wells were drilled in Block CA-1 and six exploration wells were drilled in Block CA-2 by the end2023 was 250 barrels of 2017. Theoil per day for Brunei.Total proved reserves for our Jagus East discovery in Block CA-1 now forms partat December 31, 2023 were approximately 0.3 million barrels of liquids and 188 million cubic feet of natural gas. Block CA-1 covers 2 thousand gross acres. Mexico Murphy holds a 40% working interest and is the operator of Block 5 in the deepwater Salina Basin. The block covers approximately 623 thousand gross acres, with water depths ranging from 2,300 to 3,500 feet (700 to 1,100 meters). The license contract is currently in the first additional exploration period, which expires in May 2025 and has no outstanding commitments. In 2022, an exploration well was drilled and did not find commercial hydrocarbons.VietnamThe Company holds an interest in 7.3 million gross acres, consisting of a unitized field with the GK Unit in Malaysia. On November 23, 2017, both the governments of Brunei and Malaysia signed a UFA (see Malaysia section above). Following this unitization the Company’s65% working interest in the Brunei section of the Kakap field will be adjusted. The Company hasblocks 144 and 145; and a 30% non-operating working40% interest in Block CA-2.15-1/05 and Block 15-2/17. The Company is operator of each of the three Production Sharing Contracts (PSCs).Block 15-1/05 contains the Lac Da Vang (LDV) discovered field in the Cuu Long Basin where the Declaration of Commerciality was made in January 2019, and the field Outline Development Plan was approved by Petrovietnam in August 2019. The Lac Da Trang (LDT) 1X exploration well, the last remaining commitment of the PSC, was completed in April 2019. In December 2014, the authority PetroleumBrunei approved a gas marketing plan which sets an eight-year gas holding period until December 2022. The consortium is presently carrying out a concept select study to assist in commercial discussions.VietnamIn November 2012,2023, the Company signed a PSC with Vietnam National Oilreceived government approval of the field development plan and Gas Group and PetroVietnam Exploration Productionthe Board of Directors of the Company (PVEP), where it acquired a 65% interest and operatorship of Blocks(the Board) sanctioned the project. The Company anticipates drilling an exploration well in 2024.In Block 15-2/17, the Company completed its seismic study program, which included 3D seismic reprocessing. In 2024 the Company anticipates drilling an exploration commitment well.In blocks 144 and 145. The blocks cover approximately 6.56 million gross acres and are located in145, the outer Phu Khanh Basin. The Company acquired 2D seismic for these blocks in 2013 and undertook seabed surveys in 2015 and 2016. The commitmentCompany will be seeking an extension to complete the remaining seismic commitment.Total proved reserves for Vietnam at December 31, 2023 were approximately 12.1 million barrels of acquiring, processingliquids and interpreting six hundred square kilometers (600 km2)2.8 billion cubic feet of 3D seismic has been extended to 2019.In June 2013, the Company acquired a 60% working interest and operatorship of Block 11-2/11 under another PSC. The block covers 677 thousand gross acres. The Company acquired 3D seismic and performed other geological and geophysical studies in this block in 2013. This concession carries a three-well commitment. The first exploration well was drilled in 2016 andnatural gas.Côte d’IvoireDuring the second and third wells were drilledquarter of 2023, Murphy signed PSCs as operator in 2017. These wells discovered hydrocarbons, and a commercial assessment is ongoing.In August 2015, the Company signed a farm-in agreement to acquire 35% of Block 15-1/05. PVEP is currently the operator of the block and the exploration phase expires December 2018. The exploration license calls for one exploration well commitment, which is planned to be drilled in 2018. Murphy is working with its partners on the Block 15-1/05 LDV discovery for a Declaration of Commerciality in 2018.5MexicoIn December 2016, Murphy and joint venture partners were the high bidder on Block 5, which was offered as part of Mexico’s fourth phase, Round onefive deepwater auction (Round 1.4). Murphy was formally awarded the block in March 2017. Murphy is the operator of the Block with a 30% working interest. Block 5 is locatedblocks in the deepwater Salinas basin covering approximately 640,000Tano Basin offshore Côte d’Ivoire in Africa. The five blocks have a total area of 1.5 million gross acres, (2,600 square kilometers) and water depths in this block range from 2,300 to 3,500 feet (700 to 1,100 meters). The initial exploration period for the license is four years and includeswith Murphy initially holding a work program commitment of one well. Murphy currently plans to drill an exploration well on this block in late 2018.BrazilIn September 2017, the Company entered into a farm-in agreement with Queiroz Galvão Exploração e Produção S.A. (QGEP) to acquire a 20%90% working interest in Blocks SEAL-M-351four blocks and SEAL-M-428, located in the deepwater Sergipe-Alagoas Basin, offshore Brazil. QGEP retained a 30%85% working interest in the blocks and, in a separate but related transaction, ExxonMobil Exploração Brasil Ltda. (an affiliate of ExxonMobil Corporation) farmed intofifth block. Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire holds the remaining 50% working interest asfor each block.Commitments for the operator.In addition, Murphy and its co-venturers wereinitial exploration periods across the high bidder in Brazil’s Round 14 lease salefive blocks consist of seismic reprocessing. Block CI-103 includes the Paon discovery, appraised with multiple wells by a previous operator. The PSC for Blocks SEAL-M-501 and SEAL-M-503, which are adjacentthis block also includes a commitment to SEAL-M-351 and SEAL-M-428. ExxonMobil will operate submit a field development plan for this discovery by the block and Murphy has a 20% working interest. ExxonMobil Exploração Brasil Ltda has a 50% working interest and QGEP will retain a 30% working interest in the blocks.Murphy’s total acreage position in Brazil is 746,000 gross acres over the four highly prospective blocks, offsetting several major Petrobras discoveries, with no well commitments. The Company’s total commitment is approximately $18 million, which includes signature bonuses and seismic costs, $6.4 millionend of which was paid in 2017, with the remainder to be paid in 2018.EcuadorMurphy sold its 20% working interest in Block 16, Ecuador in March 2009. In October 2007, the government2025.36Item 1. Business - ContinuedProved ReservesTotal proved reserves for crude oil, natural gas liquids and natural gas as of December 31, 20172023 are presented in the following table.Proved Reserves All Products Crude
OilNatural Gas
LiquidsNatural Gas 4Proved Developed Reserves: (MMBOE) (MMBBL) (BCF) United States 223.2 163.7 24.1 212.4 Onshore 109.4 70.3 16.3 136.7 Offshore 1113.8 93.4 7.8 75.7 Canada 202.0 22.3 1.8 1,066.7 Onshore 183.4 6.0 1.8 1,053.0 Offshore 18.6 16.3 — 13.7 Other 0.3 0.3 — 0.2 Total proved developed reserves 425.5 186.3 25.9 1,279.3 Proved Undeveloped Reserves: United States 87.9 64.3 10.2 80.7 Onshore 52.7 35.8 7.6 55.7 Offshore 235.2 28.5 2.6 25.0 Canada 213.5 13.1 1.5 1,193.4 Onshore 207.3 7.1 1.5 1,192.3 Offshore 6.2 6.0 — 1.1 Other 12.6 12.1 — 2.8 Total proved undeveloped reserves 314.0 89.5 11.7 1,276.9 Total proved reserves 3739.5 275.8 37.6 2,556.2 126.3 23.3 127.7 21.9 1.0 547.0 37.3 0.3 144.6 185.5 24.6 819.3 98.4 19.7 95.6 29.6 4.6 665.5 14.6 346.7 142.6 24.3 1,107.8 328.1 48.9 1,927.1 2 Includes proved undeveloped reserves of 2.7 MMBOE, consisting of 2.3 MMBBL oil, 0.1 MMBBL NGLs and 1.5 BCF natural gas, attributable to the noncontrolling interest in MP GOM.3 Includes proved reserves of 15.5 MMBOE, consisting of 14.0 MMBBL oil, 0.6 MMBBL NGLs and 5.3 BCF natural gas, attributable to the noncontrolling interest in MP GOM.4 Includes proved natural gas reserves to be consumed in operations as fuel of 71.3 BCF, 41.9 BCF and 2.8 BCF for the U.S. Canada and Other, respectively, with 1.2 BCF attributable to the noncontrolling interest in MP GOM.4Murphy Oil’s 2023 total proved reserves and proved undeveloped reserves increased during 2017are reconciled from 2022 as presented in the table below:(Millions of oil equivalent barrels) 1(Millions of oil equivalent barrels) 1Total
Proved
ReservesTotal Proved
Undeveloped
Reserves684.5 341.1 (5.6) 2.0 71.3 61.1 2.0 (52.9) 5.8 0.4 Sale of properties Sale of properties Sale of properties (59.7) 698.3 351.7 End of year 21 For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of oil.2 Includes 15.5 MMBOE and 2.7 MMBOE for total proved and proved undeveloped reserves, respectively, attributable to the noncontrolling interest in MP GOM.During 2017,2023, Murphy’s total proved reserves increased by 13.824.1 million barrels of oil equivalent (mmboe)(MMBOE). The most significant additionsincrease in reserves principally relates to total proved reserves related to drilling, well performance, and re-allocationextensions of capital to higher performing drilling areas86.4 MMBOE in Onshore Canada, 11.7 MMBOE in the Eagle Ford Shale, area of South Texas that added 30.712.6 MMBOE Montney gas area of Western Canada that added 25.8in Vietnam, 1.1 MMBOE and in the Kaybob Duvernay and Placid Montney areas in Canada that added 7.7 MMBOE. Drilling and well performance in the Gulf of Mexico, added 3.4 mmboe. At December 31, 2017, Murphy acquired increased working interestsand 0.9 MMBOE in two fields locatedOffshore Canada. These revisions were offset by production of 70.4 MMBOE in 2023, performance and price related reductions of 11.4 MMBOE in the Eagle Ford Shale and 1.9 MMBOE in the Gulf of Mexico, adding 4.8 MMBOE. In 2017, Murphy’s proved reservesand disposition of 5.2 MMBOE in Malaysia were reduced by 3.5 MMBOE following the results of a non-operated field equity redetermination. Murphy’s total proved undeveloped reserves at December 31, 20172023 increased 10.634.6 MMBOE from a year earlier. The proved undeveloped reserves reported in the table as extensions and discoveries during 20172023 were predominantly attributable to two areas – drilling and re-allocationfour areas: the U.S. Gulf of capital to higher performing drilling areas inMexico, the Eagle Ford Shale area ofin South Texas, Tupper Montney in Onshore Canada and the Tupper area in Western Canada. Both of these areasOffshore Vietnam. The U.S. and Canadian assets had active development work ongoing during the year.year, while the Tupper Montney had increased capital allocations and the Lac Da Vang development project in Vietnam was sanctioned. The majority of proved undeveloped reserves associated with revisions of previous estimates was the result of higher oilperformance adjustments in Tupper Montney and gas prices extending the economic life of well locations planned for development withinEagle Ford Shale and negative price revisions in the next five years.U.S. Onshore and U.S. Offshore fields, and were substantially offset by positive price revisions in Tupper Montney from decreased royalty rates and decelerated royalty incentive payouts arising from lower commodity prices. The majority of the proved undeveloped reserves migration to the proved developed category are attributable to drilling in Tupper Montney, the Gulf of Mexico, and the Eagle Ford Shale Malaysia and Tupper. the completion of the Terra Nova field life extension project in Offshore Canada. Other proved undeveloped increases resulted from sanctioned development plans for the Longclaw field in the Gulf of Mexico and Lac Da Vang field in Vietnam.The Company spent approximately $453$704 million in 20172023 to convert proved undeveloped reserves to proved developed reserves. TheIn the next three years, the Company expects to spend about $648a range of approximately $450 million in 2018, $720 to $700 million in 2019 and $716 million in 2020per year to move7currently current undeveloped proved reserves to the developed category. The anticipated level of spending in 20182024 primarily includes drilling and development in the Gulf of Mexico, Eagle Ford Shale, Kaybob, PlacidTupper Montney and TupperVietnam areas. In computing MMBOE, natural gas is converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) to one barrel of oil.At December 31, 2017,2023, proved reserves are included for several development projects, including oil developments atin the Eagle Ford Shale in South Texas, Montney shale at Tupper, the Kakap, Kikeh, Siakap fields, offshore Sabah,deepwater Gulf of Mexico, Kaybob Duvernay in MalaysiaOnshore Canada and Lac Da Vang in Vietnam; as well as natural gas developments offshore Sarawak and offshore Block H in Malaysia.Tupper Montney in Onshore Canada. Total proved undeveloped reserves associated with various development projects at December 31, 20172023 were approximately 351.7314.0 MMBOE, which represent 50%represents 42% of the Company’s total proved reserves.Certain development projects have proved undeveloped reserves that will take more than five years to bring to production. threetwo undeveloped locations that exceed this five-year window. Total reserves associated with the threetwo locations amount to less than 1% of the Company’s total proved reserves at year-end 2017.2023. The development of certain reserves extends5beyond five years due to limited well slots available,slot availability, thus making it necessary to wait for depletion of other wells prior to initiating further development of these locations. The second projectlocations or behind-pipe completions with significant capital costs that will take more than five years to develop is offshore Malaysia. The Block H development project has undeveloped proved reserves that make up 8% of the Company’s total proved reserves at year-end 2017. This operated project will take longer than five years from discovery to be completely developed due to a deferral of development and construction of FLNG facilities operated by another company. Field start up is expected to occur in 2020.Murphycategorize them as undeveloped.Murphy Oil’s Reserves Processes and PoliciesThe Company employs a ManagerAll estimates of Corporate Reserves (Manager) who is independentreserves are made in compliance with SEC Rule 4-10 of the Company’sRegulation S-X, which states that “proved oil and gas operational management. The Manager reportsreserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to the Senior Vice President, Planning & Performance, of Murphy Oil Corporation, who in turn reports to the Chief Financial Officer of Murphy Oil. The Manager makes annual presentations to the Board of Directors about the Company’s reserves. The Manager reviewsbe economically producible —from a given date forward, from known reservoirs, and discussesunder existing economic conditions, operating methods, and government regulations.” Proved reserves estimates directly with the Company’s reservoirwill generally be revised only as additional geologic or engineering staff in order to make every effort to ensure compliance with the rules and regulations of the SEC and industry. The Manager utilizes independent, well known and respected third-party firms to audit reserves. The Manager coordinates and oversees these third-party audits. The third-party audits are performed annually and under Company policy generally target coverage of at least one-third of the barrel oil-equivalent volume of the Company’s proved reserves. The Company reports its internal assessmentsdata become available or as economic conditions change. Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and only usesshould not be construed as being exact quantities, and if recovered, could be more or less than the third-party audit results as an independent assessment of itsestimated amounts.Murphy has established both internal computations. Internal audits may also be performedand external controls for estimating proved reserves that follow the guidelines set forth by the ManagerSEC for oil and qualified engineering staff from areas ofgas reporting. Crude oil and condensate, natural gas liquids (NGL) and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators (“QREs”). QREs are technical professionals embedded within the Company other than the area being audited by third parties. Each significant exploration and production office maintains one or more Qualified Reserve Estimators (QRE) on staff. Theasset teams. QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area. The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others. A QRE is professionally qualified to perform these reserves estimates due to having sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment.Thisqualification generally requires a minimum of threefive years of practical experience in petroleum engineering or petroleum production geology, with at least one yearthree years of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.officesbusiness units of the Company also employ a Regional Reserves Coordinator (RRC)Coordinators who supervisescoordinate and provide oversight of the local QREs. The RRC is usually a senior QRE that has the primary responsibility for coordinating and submitting reserves informationreserve submissions to senior management.The Company’s QREs maintain files containing pertinent data regarding each significant reservoir. Each file includes sufficient data to support the calculations or analogies used to develop the values. Examples of data included in the file, as appropriate, include: production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy or other pertinent reserve estimation data; production8performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the conclusion of the QRE stating, that in their opinion, the reserves have been calculated, reviewed, documented and reported in compliance with the regulations and guidelines contained in the reserves training manual. The Company’s reserves are maintained in an industry-recognized reservoir engineering software system, which has adequate access controls to avoid the possibility of improper manipulation of data. When reserves calculations are completed by QREs and appropriately reviewed by RRCsmanagement and the Manager, the conclusions are reviewed and discussed with the heads of the Company’s exploration and production business and other senior management as appropriate. The Company’s Controller’s department is responsible for preparing and filing reserves schedules within the Form 10-K report.companyCompany reserves estimators to ensure SEC requirements associated with reserves estimation and Form 10-K reporting are fulfilled. The trainingProved reserves are consolidated and reported through the Corporate Reserves group. Murphy’s General Manager Corporate Reserves (Reserves General Manager) leads the Corporate Reserves group that also includes materials provided to each participant that outlinesCorporate Reserve engineers and support staff, all of which are independent of the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserves estimation.Qualifications of Manager of Corporate ReservesThe Company believes that it has qualified employees preparingCompany’s oil and gas reserves estimates. Mr. F. Michael Lasswell serves as Corporateoperational management and technical personnel. The Reserves General Manager joined Murphy in 2020 and has more than 32 years of industry experience. He has a Bachelor of Science in Mechanical Engineering and is also a licensed Professional Engineer in the State of Texas. The Reserves General Manager reports to the Executive Vice President and Chief Financial Officer and makes annual presentations to the Board about the Company’s reserves. The Reserves Manager having joinedand the Company in 2012. Prior to joining Murphy, Mr. Lasswell was employed as a Regional Coordinator ofCorporate Reserve engineers review and discuss reserves at a major integrated oil company. He worked in several capacities in the reservoir engineering departmentestimates directly with the oil company from 2002Company’s technical staff in order to 2012. Mr. Lasswell earned a Bachelor’s of Science degree in Civil Engineeringmake every effort to ensure compliance with the rules and a Master’s of Science degree in Geotechnical Engineering from Brigham Young University. Mr. Lasswell has experience working in the reservoir engineering field in numerous areasregulations of the world, includingSEC.The Reserves General Manager coordinates and oversees the North Sea,third-party audits which are performed annually. In 2023, third party audits were conducted for proved reserves covering 96.6% of total proved reserves. All audits conducted during this period were within the established +/- 10.0% tolerance.Ryder Scott Company (“Ryder Scott”) performed audits for certain reserve estimates of Murphy’s U.S. Arctic, the Middle East and Asia Pacific.fields as of December 31, 2023. The Ryder Scott summary report is filed as an exhibit to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 21 years of industry experience, joining Ryder Scott over 18 years ago. He is a memberregistered Professional Engineer in the State of Texas.McDaniel & Associates (“McDaniel”) performed audits for certain reserve estimates of our Canadian fields as of December 31, 2023. The McDaniel summary report is filed as an exhibit to this Annual Report on Form 10-K. The two technical advisors for McDaniel both have over 17 years of experience in the Societyestimation and evaluation of Petroleumreserves with McDaniel. Both are registered Professional Engineers (SPE),with the Association of Professional Engineers and Geoscientists of Alberta.Gaffney, Cline & Associates Pte Ltd (“GaffneyCline”) performed audits for certain reserve estimates of our Vietnam fields as of December 31, 2023. The GaffneyCline summary report is a past memberfiled as an exhibit to this Annual Report on Form 10-K. The team lead for GaffneyCline has over 40 years of its Oilindustry experience, joining GaffneyCline over 19 years ago.6To ensure accuracy and Gas Reserves Committee (OGRC) and is also co-authorsecurity of a paper onreported reserves, the Recognition of Reserves which was published byproved reserves estimates are coordinated in industry-standard software with access controls for approved users. In addition, Murphy complies with internal controls concerning the SPE. Mr. Lasswell has also attended numerous industry training courses.More information regarding Murphy’s estimated quantities of proved reserves of crude oil, natural gas liquids and natural gas for the last three years are presented by geographic area on pages 106105 through 112of this Form 10-K report. Murphy currently has no oil and natural gas reserves from non-traditional sources. Murphy has not filed and is not required to file any estimates of its total proved oil or natural gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission.SEC. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.Crude oil, condensate and natural gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the three years ended December 31,, 2017 2023 are shown on pages 30and 32 page 34 of this Form 10-K Report. In 2017, the Company’s production of oil and natural gas represented approximately 0.1% of worldwide totals.Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 3438of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.Supplemental disclosures relating to oil and natural gas producing activities are reported on pages 104103 through 117 118 of this Form 10-K report.97Acreage and Well CountAt December 31, 2017,2023, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres attributable to Murphy’s interest.104 91 63 59 167 150 14 6 565 303 579 309 118 97 628 362 746 459 86 71 486 345 572 416 101 8 43 2 144 10 187 79 529 347 716 426 257 149 2,417 1,210 2,674 1,359 636 191 636 191 746 148 746 148 5,792 2,986 5,792 2,986 2,935 562 2,935 562 7,998 4,937 7,998 4,937 8 1 8 1 562 325 21,689 10,744 22,251 11,069 Developed Undeveloped Total Area (Thousands of acres)Gross Net Gross Net Gross Net United States Onshore 111 97 22 22 133 119 Gulf of Mexico 59 26 541 288 600 314 Total United States 170 123 563 310 733 433 Canada Onshore 129 105 175 138 304 243 Offshore 105 12 28 1 133 13 Total Canada 234 117 203 139 437 256 Mexico – – 623 249 623 249 Brazil – – 2,453 1,110 2,453 1,110 Brunei 2 – – – 2 – Vietnam – – 7,324 4,571 7,324 4,571 Côte d’Ivoire – – 1,489 1,332 1,489 1,332 Totals 406 240 12,655 7,711 13,061 7,951 Certain acreage held by the Company will expire in the next three years.Scheduled acreage expirations in 20182024 include 4274,521 thousand net acres in Block 144 in Vietnam; 427Vietnam, 52 thousand net acres in Block 145 in Vietnam; 266the Gulf of Mexico and 6 thousand net acres in Block 15-1/05Onshore Canada. Murphy has applied for and anticipates receiving lease extensions in Vietnam; 81Vietnam.Acreage currently scheduled toexpire in 2025 include 249 thousand net acres in Block 11-2/11 in Vietnam; 116Mexico, 75 thousand net acres in Block CA-1 in Brunei; 15 thousand net acres in Western Canada and 87Brazil, 6 thousand net acres in the United States. Acreage currently scheduled to expire in 2019 include 447Gulf of Mexico and 1 thousand net acres in Block CA-2Onshore Canada.Scheduled expirations in Brunei; 140 thousand net acres in Western Canada; 120 thousand net acres in Block AC/P36 in Australia; and 242026 include 27 thousand net acres in the United States. Scheduled expirations in 2020 include 415Gulf of Mexico and 6 thousand net acres in Block AC/P58 in Australia; 101 thousand net acres in Western Canada; 37 thousand net acres in Block 351 in Brazil; 37 thousand net acres in Block 428 in Brazil; and 11 thousand net acres in the United States.108As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly-owned wells. An “exploratory” well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area. A “development” well is drilled within the proved area of an oil or natural gas reservoir that is known to be productive.The following table shows the number of oil and natural gas wells producing or capable of producing at December 31, 2017.2023.Oil Wells Oil Wells Natural Gas Wells Gross Gross Net Gross Net 908 757 6 4 United States United States Gulf of Mexico Total United States 34 24 380 315 93 48 55 33 Offshore Total Canada 1,035 829 441 352 Murphy’s net wells drilled and completed in the last three years are shown in the following table.68.7 27.2 95.9 0.7 0.7 51.5 7.0 3.0 61.5 2.2 2.0 1.2 1.2 2.0 4.6 109.6 7.0 15.9 132.5 United States Canada Other Totals Productive Dry Productive Dry Productive Dry Productive Dry 2023 Exploration – 1.3 – – – – – 1.3 Development 34.1 – 15.1 – – – 49.2 — 2022 Exploration – – – – – 0.6 – 0.6 Development 29.1 – 22.1 – – – 51.2 – 2021 Exploration – 0.1 – – – – – 0.1 Development 27.9 – 14.6 – – – 42.5 – Murphy’s drilling wells in progress at December 31, 20172023 are shown in the following table. The year-end well count includes wells awaiting various completion operations. The U.S. net wells included below are essentially all locatedExploration Development Total Gross Net Gross Net Gross Net Country United States Onshore – – 6.0 1.3 6.0 1.3 Gulf of Mexico 1.0 0.1 3.0 0.8 4.0 0.9 Canada Onshore – – 11.0 11.0 11.0 11.0 Offshore – – – – – – Totals 1.0 0.1 20.0 13.1 21.0 13.2 9SustainabilityEnvironment and Climate ChangeWe understand that our industry, and the use of our products, create emissions – which raise climate change concerns. At the same time, access to affordable, reliable energy is essential to improving the world’s quality of life and the functioning of the global economy. We believe that as the energy economy transitions, oil and gas will continue to play a vital role in the Eagle Ford Shale area of South Texas.long-term energy mix.18.0 16.8 18.0 16.8 17.0 12.3 17.0 12.3 35.0 29.1 35.0 29.1 11RefiningWe are committed to reducing our GHG emissions and Marketing – Discontinued OperationsThe Company decommissioned the Milford Haven refinery unitsare focused on understanding and completed the sale of its remaining downstream assets in the U.K. in 2015 for cash proceeds of $5.5 million.mitigating our climate change risks. To guide our climate change strategy, Murphy has adopted a climate change position, and we are setting meaningful emissions reduction goals. The Company has accountedestablished a GHG emissions intensity reduction target of 15% to 20% by 2030 from our 2019 level, excluding our discontinued and divested Malaysia operations. In addition, we have endorsed the goal of eliminating routine flaring by 2030, under the current World Bank definition of routine flaring.Murphy recognizes that emissions are only one element of our total environmental footprint. Protecting natural resources is also an important factor in our overall sustainability efforts. See our 2023 Sustainability Report, located on the Company’s website, for and reported this U.K. downstream business as discontinued operations for all periods presented.EnvironmentalMurphy’s businessesdetails.Further, we are subject to various international, foreign, national, state, provincial and local environmental, health and safety laws and regulations, including related to 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 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.U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). CERCLA and similar state statutes impose joint and several liability, without regard to fault or legality of the conduct, on current and past owners or operators of a site where a release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Although CERCLA generally exempts “petroleum” from regulation, in the course of our operations, we may and could generate wastes that may fall within CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others.Water discharges. The U.S. Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and gas wastes, into regulated waters. The U.S. Oil Pollution Act (OPA) imposes certain duties and liabilities on the owner or operator of a facility, vessel or pipeline that is a source of or that poses the substantial threat of an oil discharge, or the lessee or permittee of the area in which a discharging offshore facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill.U.S. Bureau of Ocean Energy Management (BOEM) and the U.S. Bureau of Safety and Environmental Enforcement (BSEE) requirements. BOEM and BSEE have regulations applicable to lessees in federal waters that impose various safety, permitting and certification requirements applicable to exploration, development and production activities in the Gulf of Mexico and also require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met. These include, in the Gulf of Mexico, well design, well control, casing, cementing, real-time monitoring and subsea containment, among other items. Under applicable requirements, BOEM evaluates the financial strength and reliability of lessees and operators active on the U.S. Outer Continental Shelf, including the Gulf of Mexico. If the BOEM determines that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance.Air emissions and climate change. The U.S. Clean Air Act and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and other authorization requirements. Since 2009, the U.S. Environmental Protection Agency (EPA) has been monitoring and regulating GHG emissions, including carbon dioxide and methane, from certain sources in the oil and gas sector due to their association with climate change. In addition, international climate efforts, including the 2015 “Paris Agreement” and the10recent Conferences of the Parties of the UN Framework Convention on Climate Change (COP26, COP27, and COP28, respectively), have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs.Murphy is currently required to report GHG emissions from its U.S. operations in the Gulf of Mexico and onshore in south Texas and in its Canadian onshore business in British Columbia and Alberta. In Canada, Murphy is subject to GHG regulations and resultant carbon pricing programs specific to the jurisdiction of operation. Any limitations or further regulation of GHG, such as a cap and trade system, technology mandate, emissions tax, or expanded reporting requirements, could cause the Company to restrict operations, curtail demand for hydrocarbons generally, and/or cause costs to increase. Examples of cost increases include costs to operate and maintain facilities, install pollution emission controls and administer and manage emissions trading programs.Endangered and threatened species. The U.S. Endangered Species Act was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds, under the Migratory Bird Treaty Act, and marine mammals under the Marine Mammal Protection Act.As noted above, Murphy is subject to various laws and regulatory regimes governing similar matters in other jurisdictions in which it operates. More specifically, Murphy’s operations in Canada are subject to and conducted under Canadian laws and regulations that governaddress many of the mannersame environmental, health and safety issues as those in the U.S., including, without limitation, pollution and contamination, air quality and emissions, water discharges and other health and safety concerns.Health and SafetyMurphy’s commitment to safety is strong, and so are our actions to protect our workforce and communities. Our employees are our most valuable asset. Murphy strives to achieve incident-free operations through continuous improvement processes managed by the Company’s Health, Safety, Environment (HSE) Management System, which engages all personnel, contractors and partners associated with Murphy operations and facilities, and provides a consistent method for integrating HSE concepts into our procedures and programs. We work hard to build a culture of safety across our organization, with regular training, exercise drills and key targeted safety initiatives.Safety. The Company is subject to the requirements of the U.S. Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information regarding hazardous materials used or produced in Murphy’s operations be maintained and provided to employees, state and local government authorities and citizens. In Canada, the Company conducts its operations. is subject to Federal Occupational Health and Safety Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia) and the Workplace Hazardous Materials Information System.Environmental, Social and Governance (ESG) DisclosureWe publish an annual sustainability report according to internationally recognized ESG reporting frameworks and standards, including Sustainability Accounting Standards Board, Task Force on Climate-related Financial Disclosures (TCFD), Global Reporting Initiative, Ipieca and American Petroleum Institute.As this is an area of continual improvement across our industry, we strive to update our disclosures in line with operating developments and with emerging best practice ESG reporting standards. In 2023, we published our fifth annual sustainability report, located on the Company’s website.11Human Capital ManagementAt Murphy, we believe in providing energy that empowers people, and that is what our 725 employees do every day. As of December 31, 2023, we had 438 office-based employees and 287 field employees, all of whom are guided by our mission, vision, values and behaviors. Together with the Executive Leadership Team, the Vice President, Human Resources and Administration, who reports directly to our Chief Executive Officer, is responsible for developing and executing our human capital management strategy. This includes the attraction, recruitment, development and engagement of talent to deliver on our strategy, the design of employee compensation, health and welfare benefits, and talent programs. We focus on the following factors in order to implement and develop our human capital strategy:•Employee Compensation Programs•Employee Performance and Feedback•Talent Development and Training•Diversity, Equity and Inclusion•Health and Welfare BenefitsThe Company anticipates that these requirements will continueBoard receives related updates from the Vice President, Human Resources and Administration on a regular basis including the review of compensation, benefits, succession and talent development, along with diversity, equity and inclusion.Employee Compensation ProgramsOur purpose, to become more complexempower people, includes tying a portion of our employees’ pay to performance in a variety of ways, including incentive compensation and stringent inperformance-based bonus programs, while maintaining the future.Further informationbest interest of stockholders. We benchmark for market practices, and regularly review our compensation and hiring acceptance rates against the market to ensure competitiveness to attract and retain the best talent. We believe our current practices align our employees’ compensation with the interests of our stockholders, and support our focus on cash flow generation, capital return and environmental matters and their impactstewardship. For further detail on Murphy are contained in Management’sthe Company’s compensation framework please see the Compensation Discussion and Analysis section of Financial Conditionthe forthcoming Proxy Statement relating to the Annual Meeting of Stockholders on May 8, 2024.Employee Performance and ResultsFeedbackWe are committed to efforts to enhance our employees’ professional growth and development through feedback that utilizes our internal performance management system (Murphy Performance Management - MPM). The purpose of Operationsthe MPM process is to show our commitment to the development of all employees and to better align rewards with Company and individual performance. The goals of the MPM process are the following:•Drive behavior to align with the Company’s mission, vision, values and behaviors•Develop employee capabilities through effective feedback and coaching•Maintain a process that is consistent throughout the organization to measure employee performance that is tied to Company and stockholder interestsAll employees’ performance is evaluated at least annually through self-assessments that are reviewed in discussions with supervisors. Employees’ performance is evaluated on pages 25various key performance indicators set annually, including behaviors that support our mission, vision, values and 49contributions toward executing our Company’s goals/business strategy.Talent Development and TrainingEmployees are able to participate in continuous training and development, with the goal of equipping them for success and providing increased opportunities for growth. Through our digital platform, My Murphy Learning, employees now have access to LinkedIn Learning with more than 15,000 courses, Continuing Education Unit (CEU) credit and certification opportunities, and access to expert instructors. We also administer mandatory compliance training for our employees through My Murphy Learning with a 100% utilization. Finally, we provide a tuition reimbursement program for those who choose to acquire additional knowledge to increase their effectiveness in their present position or to prepare for career advancement.12To enhance employees’ commitment to the Company’s Scorecard and understanding of annual incentive plans, three training courses were introduced covering the following topics: (1) Free Cash Flow and return metrics; (2) Lease Operating Expenses (LOE) and General and Administrative; and (3) Total Recordable Incident Rate, Spill Rate and Emissions. These training opportunities, in particular, enhanced the business acumen of our employee base, as well as brought renewed focus to how we measure success.We strive to empower our leadership with programs that offer career advancement for experienced and emerging leaders. Over eighty managers participated in leadership programs, from a top rated business school, addressing focus areas such as strategic agility, enterprise thinking, building high-performing teams and enhancing trust.We encourage employee engagement and solicit feedback through internal surveys and our employee-led Ambassador program to gain insights into workplace experiences. Employees are provided opportunities to raise suggestions and collaborate with leadership to improve programs and increase their alignment with Murphy’s mission, vision, values and behaviors.To monitor the effectiveness of our human capital investment and development programs, we track voluntary turnover. This data is shared on a regular basis with our Executive Leadership Team, who use it in addition to other pertinent data to develop our human capital strategy. In 2023, our voluntary employee turnover rate was 6.0%.Health and Welfare BenefitsWe believe that doing our part to aid in maintaining the health and welfare of our employees is a critical element in Murphy’s achieving success. As such, we provide our employees and their families with a comprehensive set of subsidized benefits that are competitive and aligned to Murphy’s mission, vision, values and behaviors. We also believe that the well-being of our employees is enhanced when they can give back to their local communities or charities either through the Company Matching Gift Program, “Impact – Murphy Makes a Difference” Program or on their own and receive a Company match for donations.Finally, we offer an Employee Assistance Program that provides confidential assistance to employees and their immediate family members for mental and physical well-being, as well as legal and financial issues. We also maintain an Ethics Hotline that is available to all our employees to report, anonymously if desired, any matter of concern. Communications to the hotline, which is facilitated by an independent third party, are routed to appropriate functions, Human Resources, Law or Compliance, for investigation and resolution.Diversity, Equity and InclusionWe are committed to fostering work environments that value diversity, equity and inclusion (DE&I). This commitment includes providing equal access to and participation in programs and services without regard to race, creed, religion, color, national origin, disability, sex (including pregnancy), sexual orientation, gender identity, veteran status, age or stereotypes or assumptions based thereon. We also support interest-based groups such as sports, hobbies and charity volunteering. We welcome our employees’ differences, experiences and beliefs and we are investing in a more productive, engaged, diverse and inclusive workforce. The Board receives DE&I updates on demographic data, strategic partnerships, recruiting strategies and programs from the Vice President, Human Resources and Administration on a regular cadence.We seek input and program recommendations from our DE&I Committee and through the sponsorship of our Vice President, Human Resources and Administration. Our DE&I Committee consists of diverse employees at various levels from across the organization that share a passion for DE&I. Our Board currently includes three directors who are women, with at least one woman on each committee. Our Nominating and Governance Committee is actively focused on DE&I issues as part of its overall mandate.Female Representation (U.S. and International)December 31, 2023 Executive and Senior Level Managers 21 % First- and Mid-Level Managers 22 % Professionals 33 % Other (Administrative Support and Field) 7 % Total 22 % 13Minority 1 Representation (U.S.-Based Only)December 31, 2023 Executive and Senior Level Managers 32 % First- and Mid-Level Managers 28 % Professionals 42 % Other (Administrative Support and Field) 30 % Total 35 % 1 As defined by the U.S. Equal Employment Opportunity Commission.We believe that it is important we attract employees with diverse backgrounds where we operate and are focusing on attracting and retaining women and minorities in our workforce ensuring a vibrant talent pipeline.Website Access to SEC ReportsMurphy Oil’s internet Website address is http://www.murphyoilcorp.com. InformationThe information contained on the Company’s Website is not part of, or incorporated into, this report on Form 10-K.The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on Murphy’s Website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. You may also access these reports at the SEC’s Website at http://www.sec.gov.1214Item 1A. RISK FACTORSThe Company faces risks in the normal course of business and through global, regional and local events that could have an adverse impact on its reputation, operations, and financial performance. The Board exercises oversight of the Company’s enterprise risk management program, which includes strategic, operational and financial matters, as well as compliance and legal risks. The Board receives updates annually on the risk management processes.The following are some important factors that could cause the Company’s actual results to differ materially from those projected in any forward-looking statements. If any of the events or circumstances described in any of the following risk factors occurs, our business, results of operations and/or financial condition could be materially and adversely affected, and our actual results may differ materially from those contemplated in any forward-looking statements we make in any public disclosures.Price Risk FactorsVolatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.Among the most significant variables affectingvariable factors impacting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces. The indices against which muchMany of the Company’s production is priced have been significantly lower in the years 2015-2017 (vs. pre-2015 years), and salesfactors influencing prices forof crude oil and natural gas can be significantly differentare beyond our control. These factors include:•worldwide and domestic supplies of, and demand for, crude oil, natural gas liquids and natural gas;•the ability of the members of the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC members, for example, Russia, to agree to maintain or adjust production levels;•the production levels of non-OPEC countries, including, amongst others, production levels in U.S. markets comparedthe shale plays in the United States;•political instability or armed conflict in oil and gas producing regions, such as the Russia-Ukraine conflict and Israeli-Palestinian conflict;•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to other international markets.•changes in weather patterns and climate, including those that may result from climate change;•natural disasters such as hurricanes and tornadoes, including those that may result from climate change;•the price, availability and the demand for and of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;•the effect of conservation efforts and focus on climate-change;•technological advances affecting energy consumption and energy supply;•increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and considerations including climate change and the transition to a lower carbon economy;•the occurrence or threat of epidemics or pandemics, such as the outbreak of COVID-19, or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use or generation of alternative energy sources and fuels; and•general economic conditions worldwide, including inflationary conditions and related governmental policies and interventions.West Texas Intermediate (WTI) crude oil prices averaged approximately $51 in 2017, compared to $43$77.62 per barrel in 20162023, compared to $94.23 in 2022 and $49 per barrel$67.91 in 2015 (2014 prices averaged $93 per barrel). The closing price for WTI at the end of 2017 was approximately $60 per barrel. As demonstrated by the significant decline in WTI prices in late 2014 and further declines over 2015 and early 2016, prices can be volatile. In addition, the sales prices for sour crude oils do not always move in relation to price changes for WTI and lighter/sweeter crude oils.2021. Certain U.S. and Canadian crude oils and all crude oil produced in Malaysia, generally price offare priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the U.S. WTI prices. The most15common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH), Heavy Louisiana Light Sweet (LLS), Brent(HLS) and Malaysian crude oil indices.The average New York Mercantile Exchange (NYMEX) natural gas sales price was $2.96$2.53 per thousand cubic feet (MCF)million British Thermal Units (MMBTU) in 2017, up from $2.482023, compared to $6.38 in 2022 and $3.84 in 2021. The Company also has exposure to the Canadian benchmark natural gas price, Alberta Energy Company (AECO), which averaged C$2.64 per MCF in 20162023, compared to C$5.31 in 2022 and $2.61 per MCFC$3.63 in 2015 (20142021. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section beginning on page 51 and spot contracts providing exposure to other market prices averaged $4.34 per MCF). The closing price for NYMEX natural gasat specific sales points such as Malin (Oregon, U.S.) and Dawn (Ontario, Canada).Lower prices, should they occur, will materially and adversely affect our results of December 31, 2017, was $3.30 per MCF. Certain natural gas production offshore Sarawak have been sold in recent years at a premium to average NYMEXoperations, cash flows and financial condition. Lower oil and natural gas prices due to pricing structures built intocould reduce the sales contracts. Associatedamount of oil and natural gas produced at fieldsthat the Company can economically produce, resulting in Block K offshore Sabah, representing approximately 6% ofa reduction in the Company’s 2017proved oil and natural gas sales volumes, is sold at heavily discounted prices compared to NYMEX gas prices as stipulated inreserves we could recognize, which could impact the sales contract.itsthe results of operations in future periods. The Company seeks to hedge a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. In addition, the Company seeks to maximize realized prices for Canadian gas through a combination of physical forward sales and marketing to a variety of locations.Low oil and natural gas prices may adversely affect the Company’s operations in several ways in the future.As noted elsewhere in this report, crude oil prices were lower in the 2015-2017 period versus pre-2015 years. WTI oil prices averaged approximately $51 per barrel in 2017, but have improved to above $60 per barrel by the end of 2017 and early 2018. Lower oil and natural gas prices adversely affect the Company in several ways:·Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income.
•Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income.·Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves. The Company may restrict its capital expenditures to balance its cash positions going forward.
•Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves.·Lower oil and natural gas prices could lead to impairment charges in future periods.·Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years. Low prices could make certain of the Company’s proved reserves uneconomic, which in turn could lead to removal of certain of the Company’s 2017 year-end reported proved oil reserves in future periods. These reserve reductions could be significant.13•Lower oil and natural gas prices could lead to impairment charges in future periods, therefore reducing net income.•Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years. Low prices could make a portion of the Company’s proved reserves uneconomic, which in turn could lead to the removal of certain of the Company’s year-end reported proved oil reserves in future periods. These reserve reductions could be significant.·Lower prices for oil and natural gas could lead to weaker market prices for the Company’s common stock and could cause the Company to lower its dividend.Certain•Lower oil and natural gas prices could lead to an inability to access, renew, or replace credit facilities, and could also impair access to other sources of funding as these effects are further discussed in risk factors that follow.•Lower prices for oil and natural gas could cause the Company to lower its dividend because of lower cash flows.See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices.Murphy’s commodity price risk management may limit the Company’s ability to fully benefit from potential future price increases for oil and natural gas.The Company, routinelyfrom time to time, enters into various contracts to protect its cash flows against lower oil and natural gas prices. Because ofTo the extent that the Company enters into these contracts ifand in the event that prices for oil and natural gas increase in future periods, the Company will not fully benefit from the price improvement on all production. See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices.16Operational Risk FactorsMurphy Oil’s businesses operateoperates in highly competitive environments which could adversely affect it in many ways, including its profitability, its ability to grow,cash flows and its ability to manage its businesses.Murphy operates in the oil and gas industry and experiences competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, private equity investors and independent producers of oil and natural gas.gas, and state-owned foreign oil companies. Many of the state-ownedmajor integrated and major integratedstate-owned oil companies and some of the independent producers that compete with the Company have substantially greater resources than Murphy.In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Within the industry, Murphy competes for, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.Exploration drilling results can significantly affect the Company’s operating results.The Company drills exploratory wells which subjects its exploration and production operating results to exposure to dry hole expense, which has in the past, and may in the future, adversely affect our results of operations. The Company plans to continue assessing exploration activities as part of its overall strategy. In 2023, the Company participated in three exploration wells. The Longclaw #1 well (Green Canyon 433), located in the Gulf of Mexico, resulted in a commercial discovery while the Oso #1 (Atwater Valley 138) and Chinook #7 (Walker Ridge 425) wells, located in the Gulf of Mexico, failed to encounter commercial hydrocarbons. Additionally, the Company expensed previously suspended costs associated with the 2019 Cholula-1EXP well which was determined to be non-commercial. The Company has budgeted $120 million for its 2024 exploration program, which includes drilling two operated wells in Vietnam and two non-operated wells in the Gulf of Mexico.If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.Murphy continually depletes its oil and natural gas reserves as production occurs. In order toTo sustain and grow its business, the Company must successfully replace the oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production by obtaining rights to explore for,production. The Company must find, acquire or develop, and produce hydrocarbons in prospective areas. In addition, it must find, develop and produce and/or purchase reserves at a competitive cost to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production business, therefore, is dependent on its ability to find (and/or acquire), develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products. In response to lower oil prices in recent years, the Company reduced its exploration program in 2016 and 2017 compared to previous years’ levels, this may reduce the rate at which it is able to replace reserves. The Company continually reviews opportunities to acquire additional reserves at low cost and in 2016 acquired a 70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta. Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.Proved reserves of crude oil, natural gas liquids, (NGL) and natural gas included in this report on pages 106103 through 112 have been prepared according to the SEC guidelines by qualified Companycompany personnel or qualified independent engineers based on an unweighted average of crude oil, NGL and natural gas prices in effect at the beginning of each month of the14Under existing SEC rules, reportedIn 2023, 96.6% of the proved reserves must be reasonably certain of recovery in future periods.Murphy’s actual future oil and natural gas production may vary substantially from its reported quantity of proved reserves due to a number of factors, including:·Oil and natural gas prices which are materially different from prices used to compute proved reserves
•Oil and natural gas prices which are materially different from prices used to compute proved reserves;·Operating and/or capital costs which are materially different from those assumed to compute proved reserves
•Operating and/or capital costs which are materially different from those assumed to compute proved reserves;·Future reservoir performance which is materially different from models used to compute proved reserves, and·Governmental regulations or actions which materially impact operations of a field.17•Future reservoir performance which is materially different from models used to compute proved reserves; and•Governmental regulations or actions which materially impact operations of a field.The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2017,2023, and including noncontrolling interests, approximately 43%32% of the Company’s crude oil and condensate proved reserves, 50%31% of natural gas liquids proved reserves and 57%50% of natural gas proved reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines and well workovers.The discounted future net revenues from our proved reserves as reported on pages 116 and 117 should not be considered as the market value of the reserves attributable to our properties. As required by U.S. generally accepted accounting principles (GAAP), the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations.In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on our cost of capital, and the risks associated with our business and the crude oilrisk associated with the industry in general.Murphy is reliant on certain third party infrastructure to develop projects and natural gas business in general.Exploration drilling results can significantly affect the Company’s operating results.The Company drills exploratory wells which subjects its exploration and production operating results to exposure to dry holes expense, which may have adverse effects on, and create volatility for, the Company’s results of operations. In response to lower oil prices, the Company has reduced its exploration program from pre-2015 levels. In 2017 exploration wells were drilled offshore Vietnam and in the Gulf of Mexico. The Company’s 2018 planned exploratory drilling program includes three wells in the Gulf of Mexico, one well in Vietnam and one well in Block 5, Mexico.Potential federal or state regulations could increase the Company’s costs and/or restrict operating methods, which could adversely affect its production levels.The Company’s onshore North America oil and gas production is dependent on a technique known as hydraulic fracturing whereby water, sand and certain chemicals are injected into deep oil and gas bearing reservoirs in North America. This process creates fractures in the rock formation within the reservoir which enables oil and natural gas to migrate to the wellbore. The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada. This practice is generally regulated by the states, but at times the U.S. has proposed additional regulations under the Safe Drinking Water Act. In June 2011, the State of Texas adopted a law requiring public disclosure of certain information regarding the components used in the hydraulic fracturing process. The Provinces of British Columbia and Alberta have also issued regulations related to hydraulic fracturing activities under their jurisdictions. It is possible that the states, the U.S., Canadian provinces and certain municipalities adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected or its costs of drilling and completion could be increased.15In April 2016, the U.S. Department of the Interior’s (DOI) Bureau of Safety and Environmental Enforcement (BSEE) enacted broad regulatory changes related to Gulf of Mexico well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. These changes are known broadly as the Well Control Rule, and compliance is required over the next several years. However, some provisions remain for which BSEE future enforcement action and intent are unclear, so risk of impact leading to increased future costrelies on the Company’s Gulfavailability and capacity of Mexico operations remains.In July 2016, the DOI’s Bureau of Ocean Energy Management (BOEM) issued an updated Notice to Lesseesinfrastructure, such as transportation and Operators (NTL) providing details on revised procedures BOEM will be using to determine a lessee’s ability to carry out decommissioning obligations for activities on the Outer Continental Shelf (OCS), including the Gulf of Mexico. This revised policy became effective in September 2016processing facilities, and institutes new criteriaequipment that are often owned and operated by which the BOEM will evaluate the financial strengthothers. These third-party systems, facilities, and reliability of lessees and operators active on the OCS. If the BOEM determines under the revised policy that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. In January 2017 BOEM extended the implementation timeline for the NTL by six months for properties which have co-lessees, and in February 2017 BOEM withdrew sole liability orders issued in December 2016 to allow time for the new administration to review the financial assurance program for decommissioning. Although the Company believes the new BOEM policy will likely lead to increased costs for its Gulf of Mexico operations, it does not currently believe that the impact will be material to its operations in the Gulf of Mexico.In the future, BOEM and/or BSEE may impose new and more stringent offshore operating regulations which may adversely affect the Company’s operations.Hydraulic fracturing exposes the Company to operational and regulatory risks and third-party claims.Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas. These risks include underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or ground water contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third-party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the waste water from oil and gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of waste water, or any further restrictions placed on waste water, could curtail the Company’s operations or otherwise result in operational delays or increased costs.Climate change initiatives and other environmental rules or regulations could reduce demand for crude oil and natural gas, which may adversely impact the Company’s business.The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global greenhouse gas emissions. 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, however, after originally entering the agreement the U.S. administration has subsequently withdrawn from this agreement. The U.S. remains the only country not part of the Paris Agreement. It is possible that the Paris Agreement, if fully implemented, and other such initiatives, including environmental rules or regulations related to greenhouse gas emissions and climate change, may reduce the demand for crude oil and natural gas globally. While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the exploration and production business. The Company continually monitors the global climate change agenda initiatives and plans accordingly based on its assessment of such initiatives on its business.Capital financingequipment may not always be available to fund Murphy’s activities.Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash16flows from operations and capital funding needs may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices such as those experienced in recent years. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company periodically renews these financing arrangements based on foreseeable financing needs or as they expire. The Company has a primary bank financing facility with capacity of $1.1 billion that now matures in August 2021. There is the possibility that financing arrangementsand, if available, may not always be available at sufficient levels requireda price that is acceptable to fund the Company’s activities in future periods. AsCompany. The unavailability or high cost of December 31, 2017, the Company’s long-term debt was rated “Ba3” (stable) by Moody’s Investor Services and “BB” (stable) by Fitch Ratings. These credit ratings are below investment grade andsuch equipment or infrastructure could adversely affect our cost of capital and our ability to raise debt as needed in public markets in future periods. Additionally, in order to obtain debt financing in future years, the Company mayestablish and execute exploration and development plans within budget and on a timely basis, which could have to provide more security to its lenders. Below investment grade credit ratings by certain agencies have led to increased debt service costs for certain outstanding notes, and also made it more likely that the Company would have to post collateral such as letters of credit or cash as financial assurance of its performance under certain contractual arrangements. The Company’s primary revolving credit facility requires granting of security by the Company in certain circumstances, which have not occurred at this time. See further explanation in Note F of the Consolidated Financial Statements. The Company has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.Murphy has limited or virtually no control over several factors that could adversely affect the Company.The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, NGL and natural gas, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products. Changes in commodity prices also impact the volume of production attributed to the Company under production sharing contracts in Malaysia. Economic slowdowns, such as those experienced in 2008 and 2009, had a detrimentalmaterial adverse effect on the worldwide demand for these energy commodities, which effectively ledour business, financial condition, results of operations and cash flows.Our inability to reduced prices foraccess appropriate equipment and infrastructure in a timely manner and on acceptable terms may hinder our access to oil and natural gas for a period of time. An abundant supply of crude oil in recent years also led to a severe decline in worldwide oil prices. Lower prices for crude oil, NGL and natural gas inevitably lead to lower earnings for the Company. The low crude oil price environment in the 2015-2017 period has caused the Company to reduce spending on certain discretionary drilling programs, which in turn hurts the Company’s future production levels and future cash flow generated from operations. The Company often experiences pressure on its operating and capital expenditures in periods of strong crudemarkets or delay our oil and natural gas prices because an increase in explorationproduction.Murphy is sometimes reliant on joint venture partners for operating assets, and/or funding development projects and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry. The increase in oil prices in 2017 has led to some upward inflation pressure in oil field goods and service costs during the year.Certain of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its revenue generating properties. During 2017,2023, approximately 14%18% of the Company’s total production was at fields operated by others, while at December 31, 2017,2023, approximately 9%13% of the Company’s total proved reserves were at fields operated by others.Additionally, the Company relies on the availability of transportation and processing facilities that are often owned by others. These third-party systems and facilities may not always be available to the Company, and if available, may not be available at a price that is acceptable to the Company.Failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows.Some of Murphy’s development projects entail significant capital expenditures and have long development cycle times. As a result, the Company’s partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. Murphy’s partners are also susceptible to certain of the risk factors noted herein, including, but not limited to, commodity price declines,prices, fiscal regime changes, government project approval delays, regulatory changes, credit downgrades and regional conflict. If one or more of these factors negatively impacts a project operator’s or partners’ cash flows or ability to obtain adequate financing, or if an operator of our projects fails to adequately perform operations or fulfill its obligations under the applicable agreements, it could result in a delay or cancellation of a project, resulting in a reduction of the Company’s reserves and production, which negatively impacts the timing and receipt of planned cash flows and expected profitability.1718Murphy’s operations and earnings have been and will continue to be affected by worldwide political developments.Many governments, including those that are membersTable of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as changing fiscal regimes (including corporate tax rates), setting prices, determining rates of production, and controlling who may buy and sell the production.On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, Murphy recorded a tax expense of $274.0 million associated with the 2017 Tax Act. The charge includes the impact of a deemed repatriation of foreign income and the re-measurement of the future value of deferred tax assets and liabilities. Separately, Murphy expects to receive cash refunds or credits of $29.7 million over the next four years relating to Alternative Minimum Tax (AMT) credits generated in earlier years. Murphy continues to assess the impact of this legislation including, among other things, the carry-forward of 2017 net operating losses, the change to U.S. federal tax rates, the possible limitations on the deductibility of interest paid, the option for expensing of capital expenditures, the migration from a worldwide system of taxation to a territorial system, and the use of new anti-base erosion provisions. The tax expense recorded in 2017 is a reasonable estimate based on published guidance available at this time and is considered provisional. The ultimate impact of the 2017 Tax Act may differ from these estimates due to changes in interpretations and assumptions made by the company, as well as additional regulatory guidance that may be issued. There is substantial uncertainty regarding interpretations and details of certain aspects of the 2017 Tax Act. The impact of the legislation on our business and on holders of our common shares is uncertain and could be adverse, as well as favorable. The SEC has permitted U.S. registrants one year to complete and recognize the effects of the 2017 Tax Act. As of December 31, 2017, approximately 19% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada. In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Governments could also initiate regulations concerning matters such as currency fluctuations, currency conversion, protection and remediation of the environment, and concerns over the possibility of global warming caused by the production and use of hydrocarbon energy.A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of greenhouse gases such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act, the Canada Corruption of Foreign Officials Act, the Malaysia Anti-Corruption Commission Act, the U.K. Bribery Act, the Brazil Clean Companies Act, the Mexico General Law of the National Anti-Corruption System, and other similar anti-corruption compliance statutes.It is not possible to predict the actions of governments and hence the impact on Murphy’s future operations and earnings.PART IItem 1A. Risk Factors - ContinuedMurphy’s business is subject to operational hazards, severe weather events, physical security risks and risks normally associated with the exploration for and production of oil and natural gas.The Company operates in a variety of locales, including urban, and remote, and sometimes inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes (and other forms of severe weather), mechanical equipment failures, industrial accidents, fires, explosions, acts of war, civil unrest, piracy and acts of terrorism could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, personal injury, (including death), and property damages for which the Company could be deemed to be liable and which could subject the Company to substantial fines and/or claims for punitive damages.The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes, tropical storms and tropical storms. A number of significant oil and natural gas fields lie in offshore waters around the18world. Probably the most vulnerableextreme temperatures. Many of the Company’s offshore fields are in the U.S. Gulf of Mexico, where severe hurricanes and tropical storms have often ledcan lead to shutdowns and damages. The U.S. hurricane season runs from June through November. Moreover, scientists have predicted that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that increase significant weather events, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Although the Company maintains insurance for such risks, as described elsewhere in this Form 10-K report, due to policy deductibles and possible coverage limits, weather-related risks to our operations are not fully insured. The Company has in the past experienced operational delays in Malaysia due to tropical storms in the South China Sea.In addition, the Company has risks associated with cybersecurity attacks. Although the Company maintains processes and systems to monitor and avoid damages from security threats, there can be no assurance that such processes and systems will successfully avert such security breaches. A successful breach could lead to system disruptions, loss of data or unauthorized release of highly sensitive data. This could lead to property or environmental damages and could have an adverse effectFor additional details on the Company’s revenues and costs.In addition, certain customer and supplier assets, such as storage terminals, processing facilities, refineries and pipelines, are located in areas that may be prone to severe weather events, including hurricanes, winter storms, floods and major tropical storms, all of which may be exacerbated by climate change. Severe weather events that significantly affect facilities belonging to such customers or suppliers may reduce demand for our products and interrupt our ability to bring products to market and may therefore materially and adversely affect our results of operations, cash flows and financial condition, even if our own facilities escape significant damage.Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas.The Company’s onshore North America oil and natural gas production is dependent on a technique known as hydraulic fracturing whereby water, sand and certain chemicals are injected into deep oil and natural gas bearing reservoirs in North America. This process occurs thousands of feet below the surface and creates fractures in the rock formation within the reservoir which enhances migration of oil and natural gas to the wellbore.The risks associated with hydraulic fracturing operations include, but are not limited to, underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or groundwater contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or groundwater contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses, and third-party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the wastewater from oil and natural gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of wastewater, or any further restrictions placed on wastewater, could curtail the Company’s operations due to regulatory initiatives or natural constraints such as drought or otherwise result in operational delays or increased costs.Murphy maintains insurance againstis subject to numerous environmental, health and safety laws and regulations, and such existing and any potential future laws and regulations may result in material liabilities and costs.The Company’s operations are subject to various international, foreign, national, state, provincial and local environmental, health and safety laws, regulations, governmental actions and permit requirements, including19related to 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 methane and other GHG emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. The laws, regulations, governmental actions and permit requirements are subject to frequent change and have tended to become stricter over time and at times may be motivated by political considerations. They can impose permitting and financial assurance obligations, as well as operational controls and/or siting constraints on our business, and can result in additional capital and operating expenditures. For example, in December 2023, the U.S. EPA announced its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third-parties can monitor and report large methane emissions to the EPA. In addition, it is possible in the future, that certain but not all, hazardsregulatory bodies such as the Railroad Commission of Texas may enact regulation that bans or reduces flaring for U.S. Onshore operations, and certain regulatory bodies in Canada may decide to revoke permits or pause the issuance of permits as a result of non-compliance with, or litigation related to, environmental, health and safety laws and regulations. Compliance with such regulations could arise fromresult in capital investment which would reduce the Company’s net cash flows and profitability.Murphy also could be subject to strict liability for environmental contamination in various jurisdictions where it operates, including with respect to its operations. Thecurrent or former properties, operations and waste disposal sites, or those of its predecessors. Contamination has been identified at some locations, and the Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $500 million per occurrencehas been required, and in the annual aggregate. Generally, this insurance covers various types offuture may be required, to investigate, remove or remediate previously disposed wastes; or otherwise clean up contaminated soil, surface water or groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations. In addition to significant investigation and remediation costs, such matters can result in fines and also give rise to third-party claims related tofor personal injury death and property damage, including claims arising from “sudden and accidental” pollution events. or other environmental damage.The Company primarily uses hydraulic fracturing in the Eagle Ford Shale in South Texas and in Kaybob Duvernay and Tupper Montney in Western Canada. Texas law imposes permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations, as well as public disclosure of certain information regarding the components used in the hydraulic fracturing process. Regulations in the provinces of British Columbia and Alberta also maintains insurance coverage with an additional limitgovern various aspects of $400 million per occurrence ($850 million forhydraulic fracturing activities under their jurisdictions. It is possible that Texas, other states in which we may conduct fracturing in the future, the U.S., Canadian provinces and certain municipalities may adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected, or its costs of drilling and completion could be increased. Once new laws and/or regulations have been enacted and adopted, the costs of compliance are appraised.In addition, the U.S. Bureau of Ocean Energy Management (BOEM) and the U.S. Bureau of Safety and Environmental Enforcement (BSEE) have regulations applicable to lessees in federal waters that impose various safety, permitting and certification requirements applicable to exploration, development and production activities in the Gulf of Mexico, claimsand also require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met. These include, in the Gulf of Mexico, well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. Under applicable requirements, BOEM evaluates the financial strength and reliability of lessees and operators active on the U.S. Outer Continental Shelf. If the BOEM determines that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance.In addition, various executive orders by the current presidential administration and the Department of Interior over the course of 2021 regarding a temporary suspension of normal-course issuance of permits for fossil fuel development on federal lands and a pause on new oil and gas leases on public lands and offshore waters, and the Secretary of Interior’s related review of permitting and leasing practices, could adversely impact Murphy’s operations. Despite the pauses on oil and gas leases in 2021, in August 2022, the Inflation Reduction Act was passed by the U.S. Congress and included provisions which required the Department of Interior to hold previously announced offshore lease sales in the Gulf of Mexico and Alaska within two years. These developments demonstrate the uncertainty regarding the current presidential administration’s approach to oil20and gas leasing and permitting. For further details, see “Risk Factors – General Risk Factors – Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.”We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and sustainability considerations, including climate change and the transition to a named windstorm)lower carbon economy.Opposition toward oil and gas drilling, development, and production activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and nongovernmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti‑development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.Activism may continue to increase regardless of whether the current presidential administration in the U.S. is perceived to be following, or actually follows, through on the current president’s campaign commitments to promote decreased fossil fuel exploration and production in the U.S., allincluding as a result of the administration’s environmental and climate change executive orders described earlier in this 10-K. Our need to incur costs associated with responding to these initiatives or part of which could be applicable to certain suddencomplying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and accidental pollution events. These policies have deductibles ranging from $10 million to $25 million. The occurrence of an event that is not insured or not fully insuredadequately provided for, could have a material adverse effect on the Company’sour business, financial condition and results of operationsoperations. In addition, a change in public sentiment regarding the oil and gas industry could result in a reduction in the future.While the Company has been named a co-defendant with other oil and gas companies in lawsuits related to climate change, these lawsuits have not resulted in, and are not currently expected to result in, material liability for the Company. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition. For further details on risks related to legal proceedings more generally, see “Risk Factors - General Risk Factors - Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.Financial Risk FactorsCapital financing may not always be available to fund Murphy’s activities; and interest rates could impact cash flows.Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding requirements may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company periodically renews these financing arrangements based on foreseeable financing needs or as they expire. In November 2022, the Company entered into an $800 million revolving credit facility (RCF). The RCF is involveda senior unsecured guaranteed facility and will expire in numerous lawsuits seeking cash settlements November 2027. As of December 31, 2023, the Company had no outstanding borrowings under the RCF. See Note F for alleged personal injuries, property damagesfurther details on the RCF.The Company’s ability to obtain additional financing is affected by a number of factors, including the market environment, our operating and financial performance, investor sentiment, our ability to incur additional debt in compliance with agreements governing our outstanding debt, and the Company’s credit ratings. A ratings downgrade could materially and adversely impact the Company’s ability to access debt markets, increase the borrowing cost under the Company’s credit facility and the cost of any additional indebtedness we incur, and potentially require the Company to post additional letters of credit or other forms of collateral for certain obligations. Murphy partially manages this risk through borrowing at fixed rates wherever possible; however, rates when refinancing or raising new capital are determined by factors outside of the Company’s control.21Further, changes in investors’ sentiment or view of risk of the exploration and production industry, including as a result of concerns over climate change, could adversely impact the availability of future financing. Specifically, certain financial institutions (including certain investment advisors and sovereign wealth, pension and endowment funds), in response to concerns related to climate change and the requests and other business-related matters. Certaininfluence of these lawsuits will take many yearsenvironmental groups and similar stakeholders, have elected to resolve through court proceedingsshift some or negotiated settlements. Noneall of the currently pending lawsuits are considered individually material or aggregatetheir investments away from fossil fuel-related sectors, and additional financial institutions and other investors may elect to a material amountdo likewise in the opinion of management.The Company is exposedfuture. As a result, fewer financial institutions and other investors may be willing to credit risks associated with sales of certain of its productsinvest in, and provide capital to, third parties and associated with its operating partners.Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers. For certaincompanies in the oil and gas properties operated bysector, which, in turn, could adversely impact our cost of capital.Since 2022, the Company other companies which own partial interests may not be ableundertook several actions to meet their financial obligationreduce overall debt. Murphy plans to pay for their share of capital and operating costs as they come due. The inability of a purchaser ofcontinue with the Company’s oil or natural gas or a partnerdeleveraging initiatives, but there can be no assurance that these efforts will be successful and, if not, the Company’s financial conditions and prospects could be adversely affected. See Note F for information regarding the Company’s outstanding debt as of the Company to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.Murphy’s operations could be adversely affected by changes in foreign currency conversionexchange rates.The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, and therefore the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations.In certain countries, such as Canada and Malaysia significant levels of transactions occur in currencies other than the functional currency. In Malaysia, such transactions include tax and other supplier payments, while in Canada, certain crude oil sales are priced in U.S. dollars. In late 2016, Malaysian authorities altered the local currency rules such that 75% of the proceeds of export oil and gas sales must be converted to local currency when received; plus, beginning in 2017, resident suppliers of goods and services to the Company must be paid in local currency. Exposures associated with current and deferred income tax liability and asset19balances in Malaysia are generally not hedged. A strengthening of the Malaysian ringgit against the U.S. dollar would be expected to lead to currency gains in consolidated operations; losses would be expected if the ringgit weakens versus the dollar. In Canada, currency risk is often managed by selling forward U.S. dollars to match the collection dates for crude oil sold in that currency. On occasions, the Canadian business may hold assets or incur liabilities denominated in a currency which is not Canadian dollars which could lead to exposure to foreign exchange rate fluctuations. See also L in the Notes to Consolidated Financial Statements K for additional information on derivative contracts.The costs and funding requirements related to the Company’s retirement plans are affected by several factors.A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.Murphy has limited control over supply chain costs.The Company often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and production activities due to high oil and natural gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry. In addition, periods of inflationary pressure in the wider economy, as seen during 2022, can also lead to a similar increase in the cost of goods and services for the Company. Murphy has a dedicated procurement department focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher prices.22The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) joint venture partners and (iii) other counterparties.Murphy is exposed to credit risk in three principal areas:•Accounts receivable credit risk from selling its produced commodity to customers;•Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due•Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas pricesThe inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.General Risk FactorsWe face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.The future impact of COVID-19, or that of any other pandemic, cannot be predicted and any resurgence of disease may cause additional volatility in commodity prices. See Risk Factors, “Price Risk Factors – Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 or other pandemic, our operations will likely be impacted and decrease our ability to produce oil, natural gas liquids and natural gas. We may be unable to perform fully on our commitments and our costs may increase as a result of the COVID-19 or other outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.The COVID-19 or other pandemic could also cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events.We cannot predict the ongoing impact of the COVID-19 or other pandemic. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, including, among other factors, the duration and spread of the virus and its variants, availability, acceptance and effectiveness of vaccines along with related travel advisories, quarantines and restrictions, the recovery time of the disrupted supply chains and industries, the impact of labor market interruptions, and the impact of government interventions.Changes in U.S. and international tax rules and regulations, or interpretations thereof, may materially and adversely affect our cash flows, results of operations and financial condition.We are subject to income- and non-income-based taxes in the United States under federal, state and local jurisdictions and in the foreign jurisdictions in which we operate. Tax laws, regulations and administrative practices in various jurisdictions may be subject to significant change, with or without advance notice, due to economic, political and other conditions, and significant judgment is required in evaluating and estimating our provision and accruals for these taxes. Our tax liabilities could be affected by numerous factors, such as changes in tax, accounting and other laws, regulations, administrative practices, principles and interpretations, the mix and level or earnings in a given taxing jurisdiction or our ownership or capital structure. For example, on August 16, 2022, the United States enacted the Inflation Reduction Act of 2022, which is highly complex, subject to interpretation and contains significant changes to U.S. tax law, including, but not limited to, a 15% corporate book minimum tax for taxpayers with adjusted financial statement income exceeding an average of $1 billion over three years and a 1% excise tax on certain stock repurchases made after December 31, 2022. The U.S. Department of the Treasury and the IRS are expected to release further regulations and interpretive guidance implementing the legislation contained in the Inflation Reduction Act of 2022, but the details and timing of such regulations are subject to uncertainty at this time. The tax provisions of the Inflation Reduction Act of 2022 that23may apply to us are generally effective in 2023 or later. We continue to analyze the potential impact of the Inflation Reduction Act of 2022 on our consolidated financial statements and to monitor guidance to be issued by the U.S. Department of the Treasury. However, it is possible that further changes may be enacted to U.S. and international tax rules and regulations, including the U.S. corporate tax system, which could have a material effect on our consolidated cash taxes in the future.We may not be able to hire or retain qualified personnel to support our operations.The success of our operations is dependent upon our ability to hire and retain qualified and experienced personnel. Changes in public sentiment for oil and gas exploration, development, and production activities and considerations including climate change and the transition to a lower carbon economy may make it more difficult for us to attract such qualified personnel. Additionally, the cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. If there is a decrease in the availability of qualified personnel, this may materially and adversely affect our results of operations, cash flows and financial condition.Murphy’s sensitive information and operational technology systems and critical data may be exposed to cyber threats.The oil and gas industry has become increasingly dependent on digital technologies to conduct exploration, development, and production activities. We are no exception to this trend. As a company, we depend on these technologies to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate internally and externally, and conduct many other business activities.Maintaining the security of our technology and preventing breaches is critical to our business operation. We rely on our information systems, and our cybersecurity training and policies, to protect and secure intellectual property, strategic plans, customer information, and personally identifiable information, such as employee information.A cyber infrastructure failure or a successfully executed, undetected cyber attack could significantly disrupt business operations. It might lead to downtime, revenue loss, and increased costs for remediation. Additionally, the compromise, theft, or unauthorized release of critical data could damage our reputation, weaken our competitive edge, and negatively impact our financial stability. Due to the nature of cyber-attacks, breaches to our systems could go undetected for a prolonged period of time.As the sophistication of cyber threats continues to evolve, we may be required to dedicate additional resources to continue to modify or enhance our security measures, or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, laws and regulations governing, or proposed to govern, cybersecurity, data privacy and protection and the unauthorized disclosure of confidential or protected information, including legislation in domestic and international jurisdictions, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.From time to time, some governments intervene in the market for crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production.Murphy is exposed to regulation, legislation and policies enacted by policy makers, regulators or other parties to delay or deny necessary licenses and permits to produce or transport crude oil and natural gas. As an example, following the election and inauguration of the current U.S. President in January 2021, the U.S. Secretary of the Interior issued Order No. 3395 on January 20, 2021. This order served to potentially impact the timing of issuance of oil and gas leases, lease amendments and extension, and drilling permits on federal lands and offshore waters. Following this notice, the Department of Interior has continued to approve permits, however, Murphy may experience delays in project approvals when the order is enforced. An extension or permanency of this regime could impact the options available to Murphy for future development, reserves available for production and hence future cash flows and profitability. The Company does not hold any onshore federal lands in the U.S.24In addition, the current presidential administration has pursued other initiatives related to environmental, health and safety standards applicable to the oil and gas industry. These include an executive order in January 2021 that directed the Secretary of the Interior to halt indefinitely new oil and gas leases on federal lands and offshore waters pending a since-completed review by the Secretary of the Interior of federal oil and gas permitting and leasing practices; however, a June 2021 preliminary injunction in the U.S. District Court for the Western District of Louisiana barred the current presidential administration from implementing the pause in new federal oil and gas leases. This executive order also set forth other initiatives and goals, including procurement of carbon pollution-free electricity, elimination of fossil fuel subsidies, a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Another executive order from January 2021 called for a climate change-focused review of regulations and other executive actions promulgated, issued or adopted during the prior presidential administration. In August 2022, the Inflation Reduction Act was passed by the U.S. Congress and included provisions which required the Department of Interior to hold previously announced offshore lease sales in the Gulf of Mexico and Alaska within two years. However, on December 14, 2023, the Secretary of the Interior approved the 2024-2029 National Outer Continental Shelf Oil and Gas Leasing Program, which contemplates only three potential oil and gas lease sales in the Gulf of Mexico through 2029. These developments demonstrate the uncertainty regarding the current presidential administration’s approach to oil and gas leasing and permitting.In March 2022, the SEC proposed rules requiring disclosure of a range of climate change-related information, including, among other things, companies’ climate change risk management; short- medium- and long-term climate-related financial risks; and disclosure of Scope 1, Scope 2 and (for certain companies) Scope 3 emissions. Similar laws and regulations regarding climate change-related disclosures have been proposed or enacted in other jurisdictions, including California and the European Union. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of the rules as proposed could be costly and time consuming.These actions and any future changes to applicable environmental, health and safety, regulatory and legal requirements promulgated by the current presidential administration and Congress may restrict our access to additional acreage and new leases in the U.S. Gulf of Mexico or lead to limitations or delays on our ability to secure additional permits to drill and develop our acreage and leases or otherwise lead to limitations on the scope of our operations, or may lead to increases to our compliance costs. The potential impacts of these changes on our future consolidated financial condition, results of operations or cash flows cannot be predicted.Prices and availability of crude oil, natural gas and refined products could be influenced by political factors and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax law changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Governments could also initiate regulations concerning matters such as currency fluctuations, currency conversion, protection and remediation of the environment, and concerns over the possibility of global warming caused by the production and use of hydrocarbon energy. As of December 31, 2023, 1.7% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada.A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of GHG such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act and other similar anti-corruption compliance statutes in the jurisdictions in which we operate.It is not possible to predict the actions of governments and hence the impact on Murphy’s future operations and earnings.25Murphy’s insurance may not be adequate to offset costs associated with certain events, and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $500 million per occurrence and in the annual aggregate. Generally, this insurance covers various types of third-party claims related to personal injury, death and property damage, including claims arising from “sudden and accidental” pollution events. The Company also maintains insurance coverage for property damage and well control with an additional limit of $450 million per occurrence ($850 million for U.S. Gulf of Mexico claims), all or part of which could apply to certain sudden and accidental pollution events. These policies have deductibles ranging from $10 million to $25 million. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.Murphy could face long-term challenges to the fossil fuels business model reducing demand and price for hydrocarbon fuels.Murphy’s business model may come under more pressure from changing environmental and social trends and the related global demands for non-fossil fuel energy sources. This demand in alternative forms of energy may cause the price of our products to become more volatile and decline. Further, a reduction in demand for fossil fuels could adversely impact the availability of future financing. As part of Murphy’s strategy review process, the Company reviews hydrocarbon demand forecasts and assesses the impact on its business model and, plans and future estimates of reserves. In addition, the Company evaluates other lower-carbon technologies that could complement our existing assets, strategy and competencies as part of its long-term capital allocation strategy. The Company also has significant natural gas reserves which emit lower carbon compared to oil and liquids.The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global GHG emissions. The Paris Agreement and subsequent yearly “conferences of the parties” to the Paris Agreement have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. In November and December 2023, the international community gathered in Dubai at the 28th Conference to the Parties on the UN Framework Convention on Climate Change (COP28), during which multiple announcements were made, including a global agreement that calls for transitioning away from fossil fuels, and a pledge by about 50 oil and gas producing countries to achieve near-zero methane emissions by 2030. In addition, the federal government could issue various executive orders that may result in additional laws, rules and regulations in the area of climate change. It is possible that the Paris Agreement, COP28, government executive orders and other such initiatives, including foreign, federal and state laws, rules or regulations related to GHG emissions and climate change, may reduce the demand for crude oil and natural gas globally. In addition to regulatory risk, other market and social initiatives such as public and private initiatives that aim to subsidize the development of non-fossil fuel energy sources, may reduce the competitiveness of carbon-based fuels, such as oil and natural gas. While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the exploration and production business. With or without renewable-energy subsidies, the unknown pace and strength of technological advancement of non-fossil-fuel energy sources creates uncertainty about the timing and pace of effects on our business model. The Company continually monitors the global climate change agenda initiatives and plans accordingly based on its assessment of such initiatives on its business.Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.The Company or certain of its consolidated subsidiaries are involved in numerous legal proceedings, including lawsuits for alleged personal injuries, environmental and/or property damages, climate change and other business-related matters. Certain of these claims may take many years to resolve through court and arbitration proceedings or negotiated settlements. In the opinion of management and based upon currently known facts and circumstances, the currently pending legal proceedings are not expected, individually or in the aggregate, to have a material adverse effect upon the Company’s operations or financial condition.Item 1B. UNRESOLVED STAFF COMMENTSThe Company had no unresolved comments from the staff of the U.S. Securities and Exchange CommissionSEC as of December 31, 2017.It2023.26PART IItem 1C. CYBERSECURITYMurphy’s cybersecurity environment is led by the Company’s Information Technology (IT) group, which, in addition to cybersecurity matters, oversees the Company’s IT infrastructure. Within the IT group, the Murphy Cybersecurity Team (MCT) is responsible for monitoring and managing security of the corporate network and enterprise systems, including developing and deploying policies, technical controls, and safety protocols and responding to security threats. All members of the MCT hold globally recognized security certifications and have wide-ranging experience in cybersecurity matters. The Incident Management Team (IMT) is responsible for responding to active threats and incidents as they occur. The Chief Information Officer is a member of the IMT, and regularly provides briefings to the Chief Executive Officer, the executive leadership team, and the Audit Committee of the Board. The Audit Committee is ultimately responsible for ensuring that management has processes in place to identify and evaluate cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the Board. We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected.Murphy considers its protection from cybersecurity threats to be a core component of its overall enterprise risk management system. Murphy’s cybersecurity risk management framework consists of cyber readiness, cybersecurity governance, and risk management strategy. The cybersecurity risk management framework is incorporated into the overall enterprise risk management process through policies, procedures, periodic simulations, and constant monitoring of the cybersecurity environment for new and emerging threats. The Company also requires employees to receive regular cybersecurity training and education to mitigate cybersecurity risks. To remain informed of the cybersecurity landscape, the Company collaborates with peers, third party advisors, industry groups and policymakers.Murphy engages cybersecurity assessors, consultants, our internal auditors, and other third parties both periodically and as appropriate when cyber threats are identified. Murphy utilizes these consultants to perform forensic analysis of data published by threat actors, to monitor and scan Murphy’s systems for threat vectors, and to consult on emerging cybersecurity environment topics.Murphy utilizes industry leading technologies that focus on continuous monitoring and analytics built on machine learning and artificial intelligence to safeguard against sophisticated cyberattacks. Deployed technologies include next generation firewalls, advanced endpoint and email protection, multi-factor authentication and Managed Detection and Response.In addition to the monitoring and detection processes for its own IT systems, Murphy also has processes in place to identify cybersecurity threats associated with third party service providers and partners; these processes include industry information sharing groups, cybersecurity notification services, vendor risk assessments, and ongoing collaboration with federal agencies.Murphy has not experienced any material impacts to our business, operations, or reputation due to cyberattacks or other security-related incidents. However, we recognize cyber threats are constantly evolving and are committed to cultivating a culture of security, remaining vigilant and continually improving our cybersecurity environment and controls.27PART IItem 2. PROPERTIESDescriptions of the Company’s oil and natural gas properties are included in Item 1 of this Form 10-K report beginning on page 1. Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages 104103 to 117118 and in Note E – Property, Plant and EquipmentD beginning on page 71.77.20Executive OfficersItem 3. LEGAL PROCEEDINGSDiscussion of the RegistrantItem 4. MINE SAFETY DISCLOSURESNot applicable.28PART IInformation about our Executive OfficersPresent corporate office, length of service in office and age at February 1, 20182024 of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually, but may be removed from office at any time by the Board of Directors.Roger W. Jenkins – Age 56;62; Chief Executive Officer since August 2013. Mr. Jenkins served as President from 2013 to 2024 and Chief Operating Officer from June 2012 to August 2013.Eric M. Hambly – Age 49; President and Chief Operating Officer since February 2024. Mr. Jenkins wasHambly served as Executive Vice President, Exploration and ProductionOperations from August 2009 through August 2013 and has served as President of the Company’s exploration and production subsidiary since January 2009.Eugene T. Coleman – Age 59; Executive Vice President since December 2016. Mr. Coleman has2020 to 2023. He also served as Executive Vice President, Offshore of the Company’s explorationOnshore from 2018 to 2020 and production subsidiary from 2011 to 2017.Walter K. Compton – Age 55; Executive Vice President and General Counsel since February 2014. Mr. Compton was Senior Vice President, and General CounselU.S. Onshore of Murphy Exploration & Production Company from March 20112016 to February 2014.John W. Eckart2018. Thomas J. Mireles – Age 59;51; Executive Vice President and Chief Financial Officer since March 2015.2022. Mr. EckartMireles was Senior Vice President, and ControllerTechnical Services from December 20112018 to March 2015.Michael K. McFadyen2022. Mr. Mireles also served as the Senior Vice President, Eastern Hemisphere of Murphy Exploration & Production Company from 2016 to 2018.E. Ted Botner – Age 50;59; Executive Vice President, General Counsel and Corporate Secretary since December 2016.February 2024. Mr. McFadyen hasBotner served as Senior Vice President, General Counsel and Corporate Secretary from 2020 to 2023. He also served as Executive Vice President, OnshoreLaw and Corporate Secretary from 2015 to 2020 and Manager, Law and Corporate Secretary from 2013 to 2015.Daniel R. Hanchera - Age 66; Senior Vice President, Business Development since 2022. Mr. Hanchera served as Senior Vice President, Business Development of the Company’s explorationMurphy Exploration & Production Company from 2014 to 2022. He also served as Vice President, Business Development and production subsidiaryPlanning of Murphy Exploration & Production Company from 20112009 to 2017.Christopher D. Hulse2014.John B. Gardner – Age 39,55; Vice President, Marketing and Supply Chain since 2022. Mr. Gardner was Vice President and Treasurer from 2015 to 2022 and served as Treasurer from 2013 to 2015.Leyster L. Jumawan - Age 47; Vice President, Corporate Planning and Treasurer since 2022. Mr. Jumawan was Assistant Treasurer from 2017 to 2022.Maria A. Martinez – Age 49; Vice President, Human Resources and Administration since 2018. Ms. Martinez was Vice President, Human Resources of Murphy Exploration & Production Company from 2013 to 2018.Meenambigai Palanivelu - Age 50; Vice President, Sustainability since 2023. Ms. Palanivelu was Director, Sustainability from 2020 to 2023. Ms. Palanivelu also served as the General Manager, Planning and Performance from 2019 to 2020 and General Manager, Finance Operating Model Program Management Office from 2017 to 2019.Louis W. Utsch – Age 58; Vice President, Tax since 2018.Paul D. Vaughan – Age 57, Vice President and Controller since June 2017.2022. Mr. HulseVaughan was Vice President Finance, Onshoreand Controller, U.S., Central and South America of Murphy Exploration & Production Company from September 20152017 to June 2017.Kelli M. Hammock – Age 46; Senior Vice President, Administration since February 2014. Ms. Hammock was Vice President, Administration from December 2009 to February 2014.K. Todd Montgomery – Age 53; Senior Vice President, Planning and Performance since January 2017. Mr. Montgomery served as Senior Vice President, Corporate Planning & Services from March 2015 to January 2017.E. Ted Botner – Age 53; Vice President, Law and Secretary since March 2015. Mr. Botner was Secretary and Manager, Law from August 2013 to March 2015.Tim F. Butler – Age 55; Vice President, Tax since August 2013. Mr. Butler was General Manager, Worldwide Taxation from August 2007 to August 2013.John B. Gardner – Age 49; Vice President and Treasurer since March 2015. Mr. Gardner served as Treasurer from August 2013 to March 2015.Barry F.R. Jeffery – Age 59; Vice President, Health, Safety, Environment and Risk Management since June 2017. Mr. Jeffery was Vice President, Insurance, Security and Risk from July 2015 to June 2017.Kelly L. Whitley – Age 52;58; Vice President, Investor Relations and Communications since July 2015. Ms. Whitley joined the Company in 2015 following 20 years29PART IIMurphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item 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.Item 4. MINE SAFETY DISCLOSURESNot applicable.ItemItem 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIESThe Company’s Common Stockcommon stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,5061,974 stockholders of record as of December 31, 2017.2023. Information as to high and low market prices per share andon dividends per share by quarter for 20172023 and 20162022 are reported on page 118119 of this Form 10-K report.22Issuer Purchase of Equity Securities:The following table summarizes repurchases of our common stock occurring in the fourth quarter 2023.Period Total Number of Shares Purchased Average Price Paid Per Share 1Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs2,3(in thousands)October 1 through October 31, 2023 – $ – – $ 525,000 November 1 through November 30, 2023 1,154,348 $ 43.29 1,154,348 $ 475,000 December 1 through December 31, 2023 572,288 $ 43.66 572,288 $ 450,000 1 Amounts exclude 1% excise tax and fees on share repurchases.2 In August 2022, the Board authorized an initial share repurchase program of up to $300 million of the Company’s common stock. On October 30, 2023, the Company authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million. Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion.3 Maximum approximate dollar values reported represent amounts at end of the month. During 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program in open-market transactions for $150.0 million, excluding taxes and fees.30PART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - ContinuedSHAREHOLDER RETURN PERFORMANCE PRESENTATIONThe following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 20122018 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group. The companiesXOP Index reports a comprehensive view of the oil and gas exploration and production segment of the S&P Total Market Index which is more comparable for the Company than the S&P 500 Index. Our peer group for 2023 is presented in the table below. Callon Petroleum Company, Matador Resources Company and SM Energy Company were added to Murphy’s peer group include Anadarko Petroleum Corporation, Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Devon Energy Corporation, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Pioneer Naturalin 2023 and CNX Resources Corporation Range Resources Corporation, Southwestern Energy Company and Whiting Petroleum Corporation. was removed. This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference. 
2012 2013 2014 2015 2016 2017 100 129 103 47 69 71 100 132 151 153 170 208 100 129 113 70 100 89 23Item 6. SELECTED FINANCIAL DATA2,097,695 1,809,575 2,787,116 5,288,933 5,312,686 1,129,675 600,795 1,183,369 3,048,639 3,210,695 (310,936) (273,943) (2,255,772) 1,024,973 888,137 (311,789) (275,970) (2,270,833) 905,611 1,123,473 172,565 206,635 244,998 236,371 235,108 (1.81) (1.59) (12.94) 5.69 4.69 (1.81) (1.60) (13.03) 5.03 5.94 172,524 172,173 174,351 180,071 189,271 1.00 1.20 1.40 1.325 1.25 960,870 789,721 2,127,197 3,742,541 3,943,956 14,821 21,740 59,886 14,453 22,014 975,691 811,461 2,187,083 3,756,994 3,965,970 159 12,349 154,622 975,691 811,461 2,187,242 3,769,343 4,120,592 1.64 1.04 0.83 1.02 1.06 537,396 56,751 (277,396) 76,155 222,621 8,220,031 8,316,188 9,818,365 13,331,047 13,481,055 9,860,942 10,295,860 11,493,812 16,742,307 17,509,484 2,906,520 2,422,750 3,040,594 2,536,238 2,936,563 4,620,191 4,916,679 5,306,728 8,573,434 8,595,730 26.77 28.55 30.85 48.30 46.87 38.6 33.0 36.4 22.8 25.5 172,573 172,202 172,035 177,500 183,407 2,506 2,588 2,713 2,556 2,598 1Capital expenditures include accruals for incurred but unpaid capital activities, while property additions and dry holesThe companies in the Statementspeer groupAPA Corporation Kosmos Energy Ltd. Range Resources Corporation Callon Petroleum Company Marathon Oil Corporation SM Energy Company Coterra Energy Inc. Matador Resources Company Southwestern Energy Company Devon Energy Corporation Ovintiv Inc. Talos Energy Inc. Hess Corporation PDC Energy Inc. 1
2018 2019 2020 2021 2022 2023 Murphy Oil Corporation 100 119 56 125 210 214 Peer Group 100 108 74 147 233 220 S&P 500 Index 100 131 156 200 164 207 XOP Index 100 112 72 135 215 215 1 PDC Energy Inc. was acquired in 2023 and therefore has been excluded from the above table and graph of Cash Flows are cash-based capital expenditures and do not include capital accruals and geological, geophysical and certain other exploration expenses that are not eligible for capitalization under oil and gas accounting rules.2Excludes property additioncumulative total return.3124Item 6. RESERVEDItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDThe following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the consolidated financial statements and accompanying notes to consolidated financial statements, which are included in Item 8 of this Annual Report on Form 10-K. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See Forward-Looking Statements at the end of this section and Risk Factors under Item 1A. Discussion and analysis of 2021 results and year-over-year comparisons between 2022 and 2021 are not included in this Form 10-K and can be found in Item 7 of the 2022 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.Murphy Oil Corporation is a worldwide oil and gas exploration and production company.company with both onshore and offshore operations and properties. The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S. and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide. A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted.Significant Company operatingfinancial and financialoperational highlights during 20172023 were as follows:·Income from continuing operations before income taxes of $71.8 million (2016 loss: $493.1 million)
•Generated net income of $661.6 million and net cash provided by operating activities of $1,748.8 million;·Issued $550 million of 5.75% senior notes due 2025 and repaid $550 million of notes that were to mature in December 2017
•Produced 193 thousand barrels of oil equivalent (BOE) per day (186 thousand excluding noncontrolling interest, NCI);·Produced 163,536 barrels of oil equivalent (BOE) per day
•Sanctioned the Lac Da Vang field development project in Vietnam;·Achieved an overall lease operating expense per BOE of $7.89
•Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire;·Reduced selling and general expenses by 16% year over year
•Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico;·
•Acquired an 8% working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for a purchase price of approximately $13 million, net of closing adjustments;·Maintained approximately $1.0 billion of cash and short-term securities throughout 2017•Resumed operations at non-operated Terra Nova field in offshore Canada during the fourth quarter of 2023, with production ramping up through first quarter 2024;•Advances made under the capital allocation framework1:◦Early debt retirement of approximately $500 million, a 27% debt reduction in the year◦Repurchased shares of common stock under the share repurchase program for $150 million, excluding excise taxes, commissions and fees◦Increased cash dividends by 10% since the fourth quarter of 2022 to $0.275 per share, or $1.10 per share annualized•Achieved 134% (139% excluding NCI) total proved reserve replacement with year-end proved reserves of 739.5 million barrels of oil equivalent (724.0 million excluding NCI).1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022. On October 30, 2023, the initial share repurchase program of $300 million of the Company’s common stock was increased by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.32PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedMurphy’s continuing operations generate revenue by producing crude oil, natural gas liquids, (NGL) and natural gas in the United States Canada and MalaysiaCanada and then selling these products to customers. The Company’s revenue is highly affected by the prices of crude oil, natural gas and NGL.natural gas liquids. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products depreciation of capital expenditures, and expenses related to exploration, administration and for capital borrowedborrowing from lending institutions and note holders.Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In 2017 liquids represented 61% of total hydrocarbons produced on an energy equivalent basis. In 2018, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%. When oil-price linked natural gas in Malaysia is combined with oil production, the Company’s 2018 total expected production is approximately 70% linked to the price of oil. If the prices for crude oil and natural gas are lower in 2018 or beyond, this will have an unfavorable impact on the Company’s operating profits. As described on page 49, the Company has entered into fixed price derivative swap contracts in the United States that will reduce its exposure to changes in crude oil prices for approximately 44% of its expected 2018 U.S. oil production and holds fixed price forward delivery contracts that will reduce its exposure to changes in natural gas prices for approximately 30% of the natural gas it expects to produce in Western Canada in 2018. In addition, a further portion of Western Canada gas production is marketed to a variety of locations, diversifying risk further.Oil prices and North American natural gas prices strengthened in 2017 compared to the 2016 period. The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $50.95 in 2017, $43.32 in 2016 and $48.80 in 2015. The sales price of a barrel of Platts Dated Brent crude oil increased to $54.28 per barrel in 2017, following averages of $43.69 per barrel and $52.46 per barrel in 2016 and 2015, respectively. The WTI index increased approximately 18% over the prior year while Dated Brent experienced a 24% increase in 2017. During 2017 the discount for WTI crude compared to Dated Brent increased compared to the prior year. The average WTI to Dated Brent discount was $3.33 per barrel during 2017, compared to $0.37 per barrel in 2016 and $3.66 per barrel in 2015. In early 2018, Dated Brent has been trading at a similar premium to WTI as 2017 average levels. Worldwide oil prices began to weaken in the fall of 2014 and continued to soften throughout 2015 and into 2016. The softening of prices beginning in late 2014 and continuing into 2016 caused average oil prices for both 2015 and 2016 periods to be below the average levels achieved in 2017. Crude oil prices in early 2018 were above the 2017 average prices. The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $2.96 in 2017, $2.48 in 2016 and $2.61 in 2015. NYMEX natural gas prices in 2017 were 19% above the average price in 2016, with the increase largely due to demand generated by LNG export growth and overland deliveries to Mexico. NYMEX natural gas prices in 2016 were 5% below the average price experienced in 2015, with the price decrease generally caused by domestic production elevating inventories to record levels and much warmer than normal winter season temperatures reducing residential demand. On an energy equivalent basis, the market continued to discount North American natural gas and NGL compared to crude oil in 2017. Natural gas prices in North America in 2018 have thus far been above the average 2017 levels due to higher demand and lower inventory levels in both cases.25Results of OperationsMurphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.2017 2016 2015 71.8 (493.1) (3,282.3) (311.8) (276.0) (2,270.8) (1.81) (1.60) (13.03) (310.9) (274.0) (2,255.8) (1.81) (1.59) (12.94) (0.9) (2.0) (15.0) 0.00 (0.01) (0.09) On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, Murphy recorded2023, the Company’s net income from continuing operations was $725.2 million, a decrease of $415.6 million compared to 2022. Lower net income from continuing operations was largely driven by lower revenues and other income ($472.5 million), higher lease operating expenses ($105.1 million) and higher exploration expenses ($101.6 million), partially offset by lower other operating expense ($91.0 million) and lower income tax expense of $274.0 million directly($113.5 million). Lower revenues and other income resulted from overall lower pricing partially offset by overall higher sales volumes and lower losses on derivative instruments. Higher lease operating expenses were related to the impact of the 2017 Tax Act. The charge includes the impact of a deemed repatriation of accumulated foreign earnings and the re-measurement of deferred tax assets and liabilities. Separately, Murphy expects to receive cash refunds or credits of $29.7 million over the next four years relating to Alternative Minimum Tax (AMT) credits generated in earlier years. Murphy continues to assess the impact of this legislation including, among other things, the carryforward of 2017 net operating losses, refinement of post-1986 accumulated foreign earnings and profits computations, the change to U.S. federal tax rates, the possible limitations on the deductibility of interest expense, the option for expensing of capital expenditures, the migration from a worldwide system of taxation to a territorial system, and the use of new anti-base erosion provisions. The tax expense recorded in 2017 is a reasonable estimate based on published guidance available at this time and is considered provisional. The ultimate impact of the 2017 Tax Act may differ from these estimates due to changes in interpretations and assumptions made by the company,higher sales volumes as well as additional regulatory guidance.Murphy Oil’s net loss in 2017 included a tax chargecosts for workover and maintenance activities at Gulf of $274.0 million related toMexico operations. Higher exploration costs were the 2017 Tax Act enacted on December 22, 2017. Resultsresult of continuing operations before taxes in 2017 were improved versus 2016. In 2017, loss from continuing operations of $310.9 million ($1.81 per dilute share) worsened from a loss of $274.0 million ($1.59 per diluted share) in 2016. The resultsdry hole expense for 2017 were favorably impacted by higher revenues due to higher realized oilthe Chinook #7 (Walker Ridge 425) and natural gas sales prices, lower unrealized losses on forward sales commodity contracts, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, and lower selling and general expenses, but these were more than offset by higher tax charges (caused by higher pre-tax income and the impact of the 2017 Tax Act), higherOso #1 (Atwater Valley 138) exploration expenses, higher other expenses, higher foreign exchange charges, and higher interest expenses. In 2017 the Company’s discontinued operations was a loss of $0.9 million.Murphy Oil’s net loss in 2016 was primarily caused by low realized oil and gas priceswells, that did not fully cover allfind commercial hydrocarbons in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire, and the expensing of previously suspended exploration costs for the Cholula-1EXP well in Mexico. No losses were recorded in 2023 on derivative instruments as no fixed price derivative swaps or collar contracts were in effect during the period. Lower other expenses which included extraction costs, selling and general expense, net interest expense, impairments and redetermination expense. Results of continuing operations in 2016 were $1,981.8 million improved over 2015 due to lower impairment expense in 2016, plus lower expenses in 2016 for lease operations, depreciation, exploration, deepwater rig contract exit costs, and administration and no reoccurrence of a deferred tax charge in 2015 associated with a distribution from a foreign subsidiary. Results in 2016 included a $71.7 million after-tax gain on sale of the Company’s five percent interest in Syncrude, while 2015 results included a $218.8 million after-tax gain on sale of 10% of the Company’s oil and gas assets in Malaysia. In 2016 and 2015, the Company’s refining and marketing operations generated losses of $2.5 million and $14.8 million, respectively, which ledcontingent consideration adjustments relating to overall losses from discontinued operations in each year.Further explanations of each of these variances are found in more detailprior acquisitions in the following.26Segment Results – InGulf of Mexico. Lower income tax expense was the following table,result of lower pre-tax income.For the Company’s results of operations for the three yearsyear ended December 31, 2017, are presented by segment. More detailed reviews2023, total hydrocarbon production was 192,640 barrels of operating results for the Company’s exploration and production and other activities follow the table.2017 2016 2015 (2.6) (205.4) (615.7) 112.5 (35.9) (583.4) 224.2 171.1 (653.2) (37.5) (54.7) (158.6) 296.6 (124.9) (2,010.9) (607.5) (149.1) (244.9) (310.9) (274.0) (2,255.8) (0.9) (2.0) (15.0) (311.8) (276.0) (2,270.8) Exploration and Production – Exploration and production (E&P) continuing operations recorded a profitoil equivalent per day, an increase of $296.6 million in 201710% compared to a loss of $124.9 million in 2016 and a loss of $2,010.9 million in 2015. Crude oil price realizations averaged $51.21 per barrel in the current year compared to $42.32 per barrel in 2016, a price2022. The increase of 21% year over year. U.S. natural gas realized price per thousand cubic feet (MCF) averaged $2.49 in the current year compared to $1.89 per MCF in 2016, a price increase of 32% year over year. Canada natural gas realized price per MCF averaged US$1.97 in the current year compared to US$1.72 per MCF in 2016, a price increase of 15% year over year. Oil and gas production costs, including associated production taxes, on a per-unit basis, were $8.63 in 2017 (2016: $9.44), which together with lower oil and natural gas volumes sold, resulted in $91.3 million lower costs in 2017.2017 vs 2016 – In 2017 profit from E&P operations of $296.6 million (2016: loss of $124.9 million) improved by $421.5 million. The results for 2017 were favorably impacted by higher revenueswas principally 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 redetermination expense, partially offset by higher exploration expenses and higher other expenses.Revenues of $2,220.5 million were $415.9 million higher than 2016 as a result of higher realized oil prices and natural gas liquid prices in all operating locations and an unrealized gain of $13.7 million (2016: loss of $125.0 million) on forward commodity price contracts, gain on the sale of Seal property of $129.0 million, offset by lower sales volumes, principally in Malaysia (as a result of natural field decline) and as a result of the sale of the Syncrude asset in Western Canada. The gain on the sale of Seal property of $129.0 million was a result of the sale of this property in January 2017, with the gain based on cash proceeds of $48.8 million and a benefit from the acquirer’s acceptance of abandonment obligations.Lease operating expenses of $468.4 million were $91.0 million lower in 2017 principally as a result of the disposal of the Syncrude asset in mid-2016, the disposal of Seal property in January 2017 and also lower operating expenses in the Company’s U.S. Onshore business as a result of continued management effort to reduce costs.Depreciation, depletion and amortization expenses of $939.9 million were $97.4 million lower in 2017 due to the disposal of the Syncrude asset in mid-2016 and lower volumes produced at Block K in Malaysia.There was no impairment recorded in 2017. In 2016, impairments expenses were $95.1 million as a result of 2016 impairments on the Company’s Terra Nova field and Seal heavy oil field in Western Canada (now divested) all of which were incurred in the first quarter of 2016 following further price declines from year-end 2015 levels.Selling and general expenses of $123.7 million were $23.7 million lower in 2017 as a result of cost saving activities in the Company throughout 2017.Redetermination expense of $15.0 million in 2017 (relating to the unitization of Gumusut/Kakap (GK) and Geronggong/Jagus East fields) was $24.1 million lower than 2016 (see below). The unitization results in a revised27interest in the Kakap field in Block K Malaysia of 6.35%. Following this unitization the Company’s working interest in the Brunei section of the Kakap field will be adjusted.Exploration costs of $122.8 million were $20.9 million higher in 2017 due to higher amortization of U.S. leases and higher geological and geophysical expenses in Mexico.Other expenses of $30.7 million were higher in 2017 by $16.8 million, principally as a result of U.S. drilling inventory write downs to net realizable value. Income tax charges of $137.1 million were $292.2 million higher than 2016 due to higher profits. The effective income tax rate of 31.6% for the E&P business was 23.8% different to 2016 on absolute basis as a result of deferred tax benefits related to Canadian dispositions in the earlier year (which increased the 2016 tax credit against a 2016 pretax loss).2016 vs. 2015 – Compared to 2015, total sales volumes in 2016 for crude oil, natural gas and natural gas liquids fell 17%. Oil sale volumes were lower in 2016 primarily due to lowernew well production from the Company’s Eagle Ford Shale field and Syncrude and heavy oil fields in Canada due to well decline and significantly less drilling beginning in the last half of 2015 and continuing into 2016. Synthetic oil production in Canada decreased due to impacts from the sale of the Company’s interests in Syncrude at the end of the second quarter of 2016 and maintenance work and downtime associated with forest fires in the surrounding area leading up to the disposition. Heavy oil sales volumes in Canada were lower in 2016 due to well decline and uneconomic wells being shut-in. Lower oil production and sales in Malaysia in 2016 were primarily attributable to natural well decline in most fields, partially offset by higher production at Kakap. Natural gas liquid sales volumes decreased primarily due to lower natural gas production in the Eagle Ford Shale. Natural gas sales volumes decreased in North America due to lower gas volumes in the Gulf of Mexico primarilyfrom the Khaleesi, Mormont, Samurai field development project, new well production from Tupper Montney and lower royalty rates, partially offset by lower production volumes at other fields in the Dalmatian field and lower volumes from the Eagle Ford Shale area in south Texas, offset in part by higher gas production volumes in the Tupper area in Western Canada. Lower natural gas production in Malaysia was primarily due to higher unplanned downtime, lower net entitlement at Sarawak and more gas injection at Kikeh.Lease operating expenses of $559.4 million declined $272.9 million in 2016 compared to 2015 essentially due to sale of interest in Syncrude, lower service costs, cost saving initiatives and a lower average foreign exchange rate in Canada. Severance and ad valorem taxes of $43.8 million decreased by $22.0 million in 2016 primarily due to lower average realized sales prices for oil and natural gas volumes in the U.S. and lower well valuations due to significantly lower commodity prices.Exploration expenses of $101.9 million were $369.1 million less in 2016 than the prior year primarily due to lower dry hole costs, lower geological and geophysical costs, lower exploration costs in other foreign areas and lower undeveloped lease amortization.Selling and general expenses of $147.4 million in 2016 decreased by 17% versus 2015, as the Company implemented further key organizational changes including lowering staffing levels from the end of the prior year.Depreciation, depletion and amortization expense of $1,037.3 million fell by $570.6 million due to both lower volumes sold and lower per-unit capital amortization rates. The lower capital amortization rates were primarily the result of impairment charges in the last half of 2015 and first quarter of 2016.Impairment expense associated with asset writedowns was approximately $95.1 million in 2016 compared to $2.5 billion in 2015. The decrease was primarily due to the significant 2015 writedowns of assets in oil and natural gas fields offshore Malaysia, the Seal heavy oil field in Western Canada and fields in deepwater Gulf of Mexico due to declineadditional downtime.Results of OperationsMurphy’s Net income (loss) by type of business and geographic segment is presented below.(Millions of dollars)2023 2022 2021 Exploration and production United States $ 905.1 $ 1,521.9 $ 766.3 Canada 41.6 134.2 (16.1) Other International (65.5) (77.0) (33.5) Total exploration and production 881.2 1,579.1 716.7 Corporate and other (156.0) (438.3) (668.0) Income from continuing operations 725.2 1,140.8 48.7 Loss from discontinued operations 1(1.5) (2.1) (1.2) Net income including noncontrolling interest 723.7 1,138.7 47.5 Net income attributable to noncontrolling interest 62.1 173.7 121.2 Net income attributable to Murphy $ 661.6 $ 965.0 $ (73.7) 1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in oil prices. Impairments in 2016 were atits consolidated financial statements.E&P Continuing Operations: 2023 vs 2022The following section of Exploration and Production (E&P) continuing operations excludes the Company’s Terra Nova fieldCorporate segment, unless otherwise noted.Please also refer to Schedule 6 – Results of Operations for Oil and Seal heavy oil field in Western Canada all of which were incurredNatural Gas Producing Activities in the first quarterSupplemental Oil and Natural Gas Information section for additional supporting tables.33PART IIItem 7. Management’s Discussion and Analysis of $39.1 million ($24.1 million after taxes) in 2016 related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at its non-operated Kakap-Gumusut field in Block K Malaysia. The final redetermination adjustment will be settled in cash.Deepwater rig contract exit costs was a benefitFinancial Condition and Results of $4.3 million in 2016 due to lower final costs incurred and paid compared to estimated costs of $282.0 million recorded in 2015 for two deepwater rigs that were under contract in the Gulf of Mexico. Due to capital constraints, these rigs were released before their contract expiration dates and the remaining obligations owed in 2016 under the contracts were expensed in 2015.28Other operating expense was $60.4 million lower in the current year primarily due to recording estimated costs of remediating a site at the Seal field in a remote area of Alberta in 2015 and an adjustment of previously recorded exit costs in 2016 associated with ceasing production operations in the Republic of Congo versus a charge in 2015 for uncollectible accounts receivables from partners in the Republic of Congo.Income tax benefits in 2016 were $155.1 million compared to benefits of $1.1 billion in the prior year. The benefits reported in 2015 were the result of large pretax losses, a significant portion of which was related to impairments, plus no local income taxes owed on the Malaysia sale and a deferred tax benefit due to the purchaser assuming certain future tax payment obligations upon the Malaysia sale. The effective tax rate in 2016 was 55.4% up from 35.6% in 2015. The 2016 period was favorably affected by deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign exploration areas.A summary of oil and gas revenues is presented in the following table.913.3 650.7 1,176.9 37.9 35.1 70.4 203.7 171.7 181.0 60.7 203.0 155.1 130.0 167.7 639.9 623.7 790.6 138.2 127.6 185.4 2,088.1 1,799.5 2,775.0 29table contains selected operating statisticsare summarized income statements for the three years ended December 31, 2017.34,649 35,858 47,325 11,551 12,372 13,794 3,004 1,046 115 8,091 8,737 7,421 150 2,766 5,341 4,637 11,699 12,674 13,365 15,249 20,312 24,619 25,456 90,431 103,400 126,400 34,649 35,858 47,326 11,551 12,372 13,794 3,004 1,046 115 7,525 8,886 7,151 150 2,766 5,341 4,637 11,699 12,454 12,464 16,360 19,867 24,376 26,583 89,200 102,405 128,369 6,867 6,929 7,558 947 1,302 1,998 508 210 10 829 786 668 9,151 9,227 10,234 6,867 6,929 7,558 947 1,302 1,998 508 210 10 1,048 720 606 9,370 9,161 10,172 32,629 35,789 38,304 11,901 17,242 49,068 226,218 208,682 196,774 104,616 106,380 121,650 8,358 10,070 21,818 383,722 378,163 427,614 163,536 175,654 207,903 162,524 174,593 209,809 698.3 684.5 774.0 (Millions of dollars) 2023 2022 2021 Revenues and other income Revenue from production $ 3,376.6 $ 4,038.5 $ 2,801.2 Sales of purchased natural gas 72.2 181.7 – Other income 8.0 26.7 17.5 Total revenues and other income 3,456.8 4,246.9 2,818.7 Cost and Expenses Lease operating expenses 784.4 679.3 539.5 Severance and ad valorem taxes 42.8 57.0 41.2 Transportation, gathering and processing 233.0 212.7 187.0 Costs of purchased natural gas 51.7 172.0 – Depreciation, depletion and amortization 850.5 763.9 782.1 Impairments of assets – – 189.3 Accretion of asset retirement obligations 46.0 46.2 46.6 Total exploration expenses 234.8 133.1 69.0 Selling and general expenses 37.7 44.5 43.6 Other 56.9 141.8 31.0 Results of operations before taxes 1,119.0 1,996.4 889.4 Income tax provisions 237.8 417.3 172.7 Results of operations (excluding Corporate segment) 1$ 881.2 $ 1,579.1 $ 716.7 1The Company sold the Seal area heavy oil property in January 2017 and its 5% non-operated Includes results attributable to a noncontrolling interest in Syncrude Canada Ltd. in June 2016. MP GOM.PricingThe Company sold a 10% interest in Malaysia properties in January 2015. Production in this table includes production for these sold interests through the date of disposition.2 Natural gas converted on an energy equivalent basis of 6:1.3 At December 31.30The Company’s total crude oil and condensate production averaged 90,431 barrels per day in 2017, compared to 103,400 barrels per day in 2016 and 126,400 barrels per day in 2015. The 2017 crude oil production level was 13% below 2016. Crude oil production in the United States totaled 46,200 barrels per day in 2017, down from 48,230 barrels per day in 2016. The decrease in U.S. crude oil production year over year was primarily due to well decline and shut-ins due to weather events which was only partially offset by new drilling. Heavy crude oil production in Western Canada fell from 2,766 barrels per day in 2016 to 150 barrels per day in 2017, with the reduction attributable to the sale of Seal asset in January 2017. Crude oil volumes produced offshore Eastern Canada totaled 8,091 barrels per day in 2017, down from 8,737 barrels per day in the previous year. There was no synthetic crude oil production in Canada in 2017 compared to 4,637 barrels per day in 2016 due to the Company selling its 5% interest in Syncrude in June 2016. Crude oil production offshore Sarawak decreased from 13,365 barrels per day in 2016 to 12,674 barrels per day in 2017. Block K in Malaysia had crude oil production of 20,312 barrels per day in 2017, down from 24,619 barrels per day in 2016. Lower oil production in 2017 in Malaysia was primarily attributable to natural well decline at most fields.The Company’s total crude oil and condensate production averaged 103,400 barrels per day in 2016, compared to 126,400 barrels per day in 2015. Crude oil production in the United States totaled 48,230 barrels per day in 2016, down from 61,119 barrels per day in 2015. The 21% decrease in U.S. crude oil production year over year was primarily due to well decline and lower drilling. Heavy crude oil production in Western Canada fell from 5,341 barrels per day in 2015 to 2,766 barrels per day in 2016 due to wells shut-in and natural well performance decline in the Seal area. Crude oil volumes produced offshore Eastern Canada totaled 8,737 barrels per day in 2016, up from 7,421 barrels per day in the previous year due to less unplanned maintenance. Crude oil production offshore Sarawak decreased from 15,249 barrels per day in 2015 to 13,365 barrels per day in 2016. Block K in Malaysia had crude oil production of 24,619 barrels per day in 2016, down from 25,456 barrels per day in 2015. Lower oil production in 2016 in Malaysia was primarily attributable to natural well decline at most fields, partially offset by higher production at Kakap.The Company produced natural gas liquids (NGL) of 9,151 barrels per day in 2017, largely in line with 9,227 barrels per day produced in 2016. Eighty-five percent of the Company’s NGL production in 2017 was derived from Gulf of Mexico and Eagle Ford Shale areas in the United States.The Company’s NGL production of 9,227 barrels per day in 2016 was down from 10,234 barrels per day in 2015. The lower NGL volumes of 1,007 barrels per day in 2016 were mostly attributable to decreased natural gas produced from the Eagle Ford Shale and in the Gulf of Mexico.Worldwide sales of natural gas averaged 383.7 million cubic feet (MMCF) per day in 2017 compared to 378.2 MMCF per day in 2016. The 2017 increase in natural gas sales volumes is attributable to 8% increase in natural gas production in Canada, primarily in Tupper and Placid areas, offset in part by lower gas production in the Gulf of Mexico and in the Eagle Ford Shale area in United States. Worldwide sales of natural gas were 378.2 MMCF per day in 2016, compared to 427.6 MMCF per day in 2015. Natural gas sales volumes decreased in North America in 2016 compared to 2015 due to lower gas volume in the Gulf of Mexico primarily in the Dalmatian field and lower volume from the Eagle Ford Shale area in south Texas, offset in part by higher gas production volumes in the Tupper area in Western Canada. 31The followingfollowing table contains the weighted average sales prices for the three years ended December 31, 2017.50.49 42.11 48.14 49.24 41.63 46.80 46.68 42.01 41.06 53.39 43.12 50.54 25.12 16.40 23.28 35.59 47.56 53.26 46.02 50.13 52.72 45.27 51.50 17.70 11.51 11.18 19.57 12.84 12.82 25.00 20.63 22.31 51.00 38.30 50.55 2.49 1.88 2.24 2.49 1.92 2.36 1.97 1.72 2.35 3.55 3.21 4.23 0.24 0.25 0.24 (Weighted average sales prices) 2023 2022 2021 Crude oil and condensate – dollars per barrel United States - Onshore $ 76.96 $ 96.00 $ 66.90 United States - Offshore 177.38 94.21 66.93 Canada - Onshore 272.84 89.88 61.79 Canada - Offshore 284.20 107.47 71.39 Other 286.60 94.37 69.21 Natural gas liquids – dollars per barrel United States - Onshore $ 19.69 $ 33.85 $ 26.97 United States - Offshore 121.94 36.01 29.14 Canada - Onshore 235.87 55.65 40.18 Natural gas – dollars per thousand cubic feet United States - Onshore $ 2.26 $ 6.04 $ 3.83 United States - Offshore 12.78 6.97 3.67 Canada - Onshore 22.06 2.76 2.43 1 Prices include the effect of noncontrolling interest in MP GOM.2 U.S. dollar equivalent.234PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedThe following table contains benchmark prices relevant to the Company soldfor the Seal area heavy oil property in January 2017 and its 5% non-operatedthree years ended December 31, 2023.(Average price for the period) 2023 2022 2021 Oil and NGLs WTI ($/BBL) $ 77.62 $ 94.23 $ 67.91 Natural gas NYMEX ($/MMBTU) 2.53 6.38 3.84 AECO (C$/MCF) 2.64 5.31 3.63 Production VolumesThe following table contains hydrocarbons produced during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.(Barrels per day unless otherwise noted) 2023 2022 2021 Net crude oil and condensate United States - Onshore 24,070 24,437 25,655 United States - Offshore 173,473 65,411 60,717 Canada - Onshore 2,937 4,005 5,312 Canada - Offshore 3,020 2,812 3,765 Other 250 700 256 Total net crude oil and condensate 103,750 97,365 95,705 Net natural gas liquids United States - Onshore 4,617 5,181 5,092 United States - Offshore 15,924 4,597 4,176 Canada - Onshore 681 903 1,117 Total net natural gas liquids 11,222 10,681 10,385 Net natural gas – thousands of cubic feet per day United States - Onshore 25,863 29,050 28,565 United States - Offshore 170,239 63,380 61,240 Canada - Onshore 369,906 310,230 277,790 Total net natural gas 466,008 402,660 367,595 Total net hydrocarbons - including NCI 2,3192,640 175,156 167,356 Noncontrolling interest Net crude oil and condensate – barrels per day (6,210) (7,452) (8,623) Net natural gas liquids – barrels per day (220) (280) (303) Net natural gas – thousands of cubic feet per day (2,089) (2,468) (3,236) Total noncontrolling interest 2,3(6,778) (8,143) (9,465) Total net hydrocarbons - excluding NCI 2,3185,862 167,013 157,891 Estimated total proved net hydrocarbon reserves- million equivalent barrels 3,4739.5 715.4 716.9 1 Includes net volumes attributable to a noncontrolling interest in Syncrude Canada Ltd.MP GOM.2 Natural gas converted on an energy equivalent basis of 6:1.3 NCI – noncontrolling interest in June 2016.3 Prices areMP GOM.4 December 31, 2023, 2022 and 2021, include 15.5 MMBOE, 18.2 MMBOE and 18.4 MMBOE, respectively, relating tononcontrolling interest.35PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedSales VolumesThe following table contains hydrocarbons sold during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.(Barrels per day unless otherwise noted) 2023 2022 2021 Net crude oil and condensate United States - Onshore 24,070 24,437 25,655 United States - Offshore 173,373 64,840 60,544 Canada - Onshore 2,937 4,005 5,312 Canada - Offshore 2,559 3,002 3,559 Other 349 663 195 Total net crude oil and condensate 103,288 96,947 95,265 Net natural gas liquids United States - Onshore 4,617 5,181 5,092 United States - Offshore 15,924 4,597 4,176 Canada - Onshore 681 903 1,117 Total net natural gas liquids 11,222 10,681 10,385 Net natural gas – thousands of cubic feet per day United States - Onshore 25,863 29,050 28,565 United States - Offshore 170,239 63,380 61,240 Canada - Onshore 369,906 310,230 277,790 Total net natural gas 466,008 402,660 367,595 Total net hydrocarbons - including NCI 2,3192,178 174,738 166,916 Noncontrolling interest Net crude oil and condensate – barrels per day (6,200) (7,369) (8,605) Net natural gas liquids – barrels per day (220) (280) (303) Net natural gas – thousands of cubic feet per day (2,089) (2,468) (3,236) Total noncontrolling interest 2,3(6,768) (8,060) (9,447) Total net hydrocarbons - excluding NCI 2,3185,410 166,678 157,469 1 Includes net volumes attributable to a noncontrolling interest in MP GOM.2 Natural gas converted on an energy equivalent basis of payments under6:1.3 NCI – noncontrolling interest in MP GOM.36PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedRevenues from ProductionThe Company’s production revenues by country and product were as follows:(Millions of dollars) 2023 2022 2021 Revenues from production United States - Oil $ 2,748.5 $ 3,085.9 $ 2,105.2 United States - Natural gas liquids 80.6 124.4 94.6 United States - Natural gas 92.7 225.3 121.7 Canada - Oil 156.7 249.2 212.5 Canada - Natural gas liquids 8.9 18.3 16.4 Canada - Natural Gas 278.2 312.6 245.9 Other - Oil 11.0 22.8 4.9 Total revenues from production $ 3,376.6 $ 4,038.5 $ 2,801.2 Revenues from production in 2023 decreased by $661.9 million compared to 2022. Lower revenues from U.S. E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher overall sales volumes from the termsGulf of Mexico. Higher sales volumes were driven by new well performance from the Khaleesi, Mormont, Samurai field development project, and were partially offset by lower sales volumes at other fields. Lower revenues from Canadian E&P was primarily attributable to lower realized prices and lower sales volumes at Kaybob Duvernay partially offset by higher sales volumes at Tupper Montney. Lower sales volumes at Kaybob Duvernay were primarily due to the divestment of certain non-core operated Kaybob Duvernay assets and all of the respective production sharing contracts.Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 34.Other IncomeOther income was $8.0 million in 2023, a decrease of $18.7 million compared to 2022. Lower other income was primarily the result of a gain on sale of the Thunder Hawk field in the third quarter of 2022.37PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedLease Operating and Transportation, Gathering and Processing ExpensesThe Company’s average worldwide realized sales price for crude oiltotal lease operating expenses and condensate was $51.21 per barreltransportation, gathering and processing expenses by geographic area were as follows:(Millions of dollars) (Dollars per equivalent barrel) 2023 2022 2021 2023 2022 2021 Lease operating expenses United States – Onshore $ 150.3 $ 137.6 $ 115.7 $ 12.48 $ 10.94 $ 8.93 United States – Offshore 480.4 385.1 290.7 14.46 13.19 10.63 Canada – Onshore 140.3 139.5 119.4 5.89 6.75 6.20 Canada – Offshore 11.5 15.6 16.9 12.30 14.20 13.04 Other 1.9 1.5 (3.2) 14.94 6.25 (44.94) Total lease operating expenses $ 784.4 $ 679.3 $ 539.5 $ 11.18 $ 10.65 $ 8.86 Transportation, gathering and processing United States – Onshore $ 12.7 $ 18.4 $ 26.1 $ 1.05 $ 1.47 $ 2.02 United States – Offshore 144.3 123.8 100.4 4.34 4.24 3.67 Canada – Onshore 72.2 65.3 57.4 3.03 3.16 2.98 Canada – Offshore 3.8 5.2 3.1 4.12 4.76 2.36 Total transportation, gathering and processing $ 233.0 $ 212.7 $ 187.0 $ 3.32 $ 3.34 $ 3.07 Lease operating expenses and transportation, gathering and processing expenses in 20172023 increased by $105.1 million and $20.3 million, respectively, compared to $42.38 per barrel in 20162022. Higher lease operating expenses and $47.99 per barrel in 2015. The average realized crude oil sales price was approximately 21% higher in 2017 comparedincreased transportation, gathering and processing expenses from U.S. E&P were primarily due to the prior year. West Texas Intermediate (WTI) crude oil averaged 18% more in 2017 compared to 2016. Dated Brent and Kikeh oil sold for approximately 24% and 22% higher in 2017, respectively, while Light Louisiana Sweet crude oil sold at 20% above 2016 levels. The average realized sales prices for U.S. crude oil and condensate amounted to $50.19 per barrel in 2017, 20% higher than 2016. Heavy oil produced in Canada averaged a sales price of $25.12 per barrel in 2017, a 53% increase from 2016. The average sales price for crude oil produced offshore Eastern Canada increased 24% to $53.39 per barrel in 2017. Crude oil sold in Malaysia averaged $52.93 per barrel in 2017, 16% higher than $45.52 in 2016.The Company’s average worldwide realized sales price for crude oil and condensate was $42.38 per barrel in 2016 compared to $47.99 per barrel in 2015. The average realized crude oil sales price was 12% lower in 2016 compared to 2015. WTI crude oil averaged 11% less in 2016 compared to 2015. Dated Brent and Kikeh oil each sold for approximately 16% less in 2016, while Light Louisiana Sweet crude oil sold at 14% below 2015 levels. The average realized sales prices for U.S. crude oil and condensate amounted to $41.99 per barrel in 2016, 12% lower than 2015. Heavy oil produced in Canada averaged $16.40 per barrel in 2016, a 30% decrease from 2015. The average sales price for crude oil produced offshore Eastern Canada declined 15% to $43.12 per barrel in 2016. The average realized sales price for the Company’s synthetic crude oil was $35.59 per barrel in 2016, down 25% from the prior year. Crude oil sold in Malaysia averaged $45.52 per barrel in 2016, 11% lower than in 2015.The average sales price for NGL in 2017 was higher than prices realized during 2016, with a significant increase in prices in the United States. NGL was sold in the U.S. for an average of $17.93 per barrel in 2017, up 53% from 2016. NGL produced in Malaysia in 2017 was sold for an average of $50.99 per barrel, 33% above the 2016 average of $38.30 per barrel.32The average sales price for NGL in 2016 was on par with prices realized during 2015. NGL was sold in the U.S. for an average of $11.72 per barrel in 2016, up 1% from the average price of $11.55 per barrel in 2015. NGL produced in Malaysia in 2016 was sold for an average of $38.30 per barrel, 24% below the 2015 average of $50.55 per barrel.North American natural gas prices were also higher in 2017 than during 2016, essentially driven by an overall increase in commodity prices and a colder winter. The average posted price at Henry Hub in Louisiana was $2.96 per MMBTU in 2017 compared to $2.48 per MMBTU in 2016 and $2.61 per MMBTU in 2015. In 2017, U.S. natural gas was sold at an average of $2.49 per thousand cubic feet (MCF), a 32% increase compared to 2016. Natural gas sold in Canada averaged $1.97 per MCF in 2017, up 15% from 2016. Natural gas sold in 2017 from Sarawak, Malaysia averaged $3.55 per MCF, up 11% from the prior year.North American natural gas prices were weaker in 2016 than 2015, essentially driven by an unseasonably warm winter demand season. The average posted price at Henry Hub in Louisiana was $2.48 per MMBTU in 2016 compared to $2.61 per MMBTU in 2015 and $4.33 per MMBTU in 2014. In 2016, U.S. natural gas was sold at an average of $1.89 per MCF, an 18% decrease compared to 2015. Natural gas sold in Canada averaged $1.72 per MCF in 2016, down 27% from 2015. Natural gas sold in 2016 from Sarawak, Malaysia averaged $3.21 per MCF, down 24% from the prior year.Based on 2017 sales volumes and deducting taxes at 35%, each $1.00 per barrel oil sales price fluctuation and $0.10 per MCF gas sales price fluctuation would have affected 2017 revenue from exploration and production operations by $15.9 million and $6.2 million, respectivelyProduction-relatedhigher operating expenses for continuing explorationadditional workover and production operations duringmaintenance activities from the last three years are shown in the following table.2017 2016 2015 468.4 559.4 832.3 43.7 43.8 65.8 939.9 1,037.3 1,607.9 1,452.0 1,640.5 2,506.0 33Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.2017 2016 2015 7.35 9.10 10.27 2.46 2.07 2.50 25.64 25.83 26.71 13.71 9.28 9.42 0.02 0.01 20.20 23.06 22.60 4.95 5.26 4.65 0.10 0.30 0.34 9.92 10.61 12.78 9.61 8.58 14.34 12.95 11.08 12.51 5.24 5.41 7.82 8.09 8.68 18.78 14.13 11.23 13.20 14.60 13.60 26.25 7.89 8.75 10.87 0.74 0.69 0.86 15.85 16.24 21.00 7.89 7.87 9.21 0.74 0.66 0.84 15.85 16.41 21.53 Lease operating expenses totaled $468.4 million in 2017, compared to $559.4 million in 2016 and $832.3 million in 2015. Lease operating expense per BOE for the overall Company was $7.89 per BOE, $0.86 per BOE lower than 2016. Lease operating expense per BOE in the Eagle Ford Shale was $7.35 which was $1.75 per BOE lower than 2016 due to cost saving initiatives, partly offset by increases in service costs. No lease operating expense was incurred for Syncrude operations (2016: $41.15 per BOE) as a result of the disposal of this business in mid-2016. Lease operating expense per BOE in Canada (excluding Syncrude) was $5.67 per BOE which was $0.21 per BOE lower due to lower costs at the Seal operations and higher volumes at Kaybob and Placid. Lease operating expense per BOE in Gulf of Mexico was $13.71 per BOE which was $4.43 higher than 2016operations.Depreciation, Depletion and Amortization ExpenseThe Company’s depreciation, depletion and amortization expense by geographic area were as a result of workover expenses on the Kodiak well. Lease operating expense per BOE at Sarawak was $5.24 which was $0.17 per BOE lower. Lease operating expense per BOE at Block K was $14.13, which was $2.90 higher than 2016 due to a 2016 credit for costs from a non-operating partner.Lease operating expenses totaled $559.4 million in 2016, compared to $832.3 million in 2015 and $1,089.9 million in 2014. Lease operating expense per BOE in the Eagle Ford Shale decreased $1.17 on a per BOE due to lower34(Millions of dollars) (Dollars per equivalent barrel) 2023 2022 2021 2023 2022 2021 Depreciation, depletion and amortization expense United States – Onshore $ 316.7 $ 321.4 $ 356.4 $ 26.29 $ 25.55 $ 27.50 United States – Offshore 389.3 295.6 260.1 11.72 10.12 9.51 Canada – Onshore 133.4 128.1 147.2 5.60 6.20 7.64 Canada – Offshore 8.8 13.4 16.6 9.47 12.25 12.80 Other 2.3 5.4 1.8 18.05 22.19 26.78 Total depreciation, depletion and amortization expense $ 850.5 $ 763.9 $ 782.1 $ 12.12 $ 11.98 $ 12.84 service costs and cost-saving initiatives offset in part by lower volumes produced. Lease operating expense for conventional operations in Canada improved in 2016 by $0.30 per BOE due to lower costs in the Seal heavy oil area and a lower Canadian dollar exchange rate, offset in part by increased cost sharing for third-party processing in the Tupper area. Synthetic oil operations costs per barrel increased by $2.27 per BOE primarily due to lower volumes produced prior to the disposition and higher maintenance cost resulting from unplanned downtime, offset in part by a lower Canadian dollar exchange rate. Lease operating expense at Sarawak decreased by $2.41 per BOE and benefited from lower logistics and maintenance cost in the 2016 period. Operating expense in Block K decreased by $1.97 per BOE and benefited from higher volumes produced at the main Kakap field.Severance and ad valorem taxes totaled $43.7 million in 2017, $43.8 million in 2016 and $65.8 million in 2015. Severance and ad valorem taxes in the U.S. in 2017 compared to 2016 were in line on an absolute basis. Severance and ad valorem taxes in the U.S. in 2016 compared to 2015 were lower primarily due to weaker average commodity prices in the Eagle Ford Shale and lower well valuations.for exploration and production operations totaled $939.9(DD&A) in 2023 increased by $86.6 million in 2017 and $1,037.3 million in 2016 and $1,607.9 million in 2015. The $97.4 million decrease in 2017 compared to 20162022. Higher DD&A was primarily due to lower per-unit capital amortization rates and lower oil volumes sold. Gulf of Mexico depreciation rate per BOE decreased in 2017 due to lower cost production mix. Depreciation per BOE in other countries were in line with 2016.Depreciation, depletion and amortization expense for exploration and production operations totaled $1,037.3 million in 2016 and $1,607.9 million in 2015. The $570.6 million decrease in 2016 compared to 2015 was primarily due to lower per-unit capital amortization rates and lower oil and natural gas volume sold. Eagle Ford Shale rate per equivalent barrel decreased due to reserve additions and cost improvements on 2016 drilling activities. The unit cost in the Gulf of Mexico decreased in 2016 due to reserve additions, mix of production and lower unit rates due to impairment of assets. Canada conventional operations rate per barrel of oil equivalent decreased in 2016 due to a lower Canadian dollar exchange rate, higher mix of production from the Tupper area and property impairments. Depreciation per barrel in both Sarawak and Block K improved in 2016 due primarily to the impairment of these assets in the prior year.Exploration expenses for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages 114 and 115 on this Form 10-K report. Expenses other than undeveloped lease amortization are included in the capital expenditures total for exploration and production activities.(4.2) 15.1 296.8 22.5 13.5 49.9 42.7 29.9 48.8 61.0 58.5 395.5 61.8 43.4 75.4 122.8 101.9 470.9 Dry hole expense in 2017 was a credit of $4.2 million, which was $19.3 million lower than 2016 primarily due to credits relating to wells drilled in prior years. Dry hole cost in other foreign areas of $3.0 million credit in 2017 was primarily attributable to credits on two 2011 wells in Brunei Block CA-2. Geological and geophysical (G&G) expense in 2017 of $22.5 million was $9.0 million higher than 2016 primarily driven by $5.8 million of charges for Block CA-2 in Brunei, $3.3 million for higher spending in Vietnam, $2.5 million in the U.S., $1.1 million in Malaysia, and $1.1 million in Brazil, offset primarily by lower spending of $2.9 million in Canada offshore and $1.2 million in Mexico.Other exploratory costs in 2017 of $42.7 million was $12.8 million higher compared to 2016 primarily due to higher spending of $4.2 million in Mexico, $2.6 million in Australia, $2.5 million in Brazil, and $1.9 million in Brunei.Undeveloped lease amortization costs in 2017 of $61.8 million was $18.4 million higher in 2017 primarily due to $23.5 millionresult of higher lease amortization in the Gulf of Mexico, $7.9 million of lease amortization in Midland Basin, offset by lower lease amortization of $9.5 million at Eagle Ford Shale and $2.6 million at Tupper West.Dry hole expense in 2016 of $15.1 million was $281.7 million lower than 2015 primarily due to lower overall exploration drilling. Dry hole cost in 2016 in Malaysia of $4.5 million is primarily attributable to one unsuccessful well in Block SK 314A. Dry hole cost in other foreign areas of $10.2 million in 2016 is primarily attributable to one unsuccessful well in Block 11-2/11 in Vietnam. 35G&G expense in 2016 of $13.5 million was $36.4 million lower than 2015 primarily due to reduced spending in Australia, Vietnam and Gulf of Mexico. Other exploratory costs in 2016 of $29.9 million was $18.9 million lower compared to 2015 due to reduced spending in Australia, Equatorial Guinea, Namibia, and Gulf of Mexico. Undeveloped lease amortization costs in 2016 of $43.4 million was $32.0 million lower than 2015 primarily due to lower lease relinquishments in the Eagle Ford Shale area during 2016.The exploration and production business recorded expenses of $42.6 million in 2017, $46.7 million in 2016 and $48.7 million in 2015 for accretion on discounted abandonment liabilities. Because the liability for future abandonment of wells and other facilities is carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment. The $4.1 million decrease in 2017 compared to 2016 primarily related to lower abandonment liabilities resulting from the Canadian Seal asset disposition, changes in estimates and a lower Canadian dollar exchange rate. The $2.0 million decrease in 2016 compared to 2015 related primarily to lower abandonment liabilities resulting from the Canadian Syncrude asset disposition, changes in estimates and a lower Canadian dollar exchange rate.The effective income tax rate for exploration and production continuing operations was 31.6% in 2017, 55.4% in 2016 and 35.6% in 2015. The effective rate in 2017 was lower than 2016 as a result of 2016 deferred tax benefits recognized related to the Canadian Syncrude asset disposition and income tax benefits on investments in foreign exploration areas; in 2016 these items increased the tax credit reported on a pre-tax loss and hence increased the effective tax rate.The effective tax rate in 2016 was greater than the 2015 effective tax rate as well as the statutory U.S. tax rate of 35.0%. The 2016 period benefited from deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign exploration areas; these items increased the tax credit reported on the 2016 pre-tax loss and hence increased the effective tax rate.At December 31, 2017, 142.7 million barrels of the Company’s crude oil and condensate proved reserves, 24.4 million barrels of NGL proved reserves and 167.0 billion cubic feet of natural gas proved reserves were undeveloped. On a worldwide basis, the Company spent approximately $452.9 million in 2017, $494.3 million in 2016, and $1.74 billion in 2015 to develop proved reserves.At December 31, 2017, 98.3 million barrels of the Company’s U.S. crude oil proved reserves, 19.7 million barrels of U.S. NGL proved reserves and 95.6 billion cubic feet of U.S. natural gas proved reserves were undeveloped. In the U.S., total proved undeveloped reserves represent 44% of total proved reserves on a barrel of oil equivalent basis as of December 31, 2017. Approximately 91% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company’s Eagle Ford Shale operations in South Texas. Further drilling and facility construction are generally required to reclassify the undeveloped reserves in the Eagle Ford Shale area to developed reserves. The deepwaters of the Gulf of Mexico accounted for the remaining 9% of proved undeveloped reserves at December 31, 2017. In the Western Canadian Sedimentary Basin, undeveloped natural gas proved reserves totaled 665.5 billion cubic feet, with the migration of these reserves, dependent on both development drilling and completion of processing and transportation facilities. In Block K Malaysia, oil proved undeveloped reserves of 12.8 million barrels are primarily at the Kikeh field, where undeveloped proved oil reserves are subject to further drilling before being reclassified to developed. Also in Malaysia, there were 346.7 billion cubic feet of undeveloped natural gas proved reserves at various offshore fields at year-end 2017. These undeveloped natural gas reserves in Malaysia are mainly associated with Block H, where a development project commenced following sanction in 2014. First production at Block H is currently expected in 2020.36Corporate – The after-tax costs of corporate activities, which include interest income and expense, foreign exchange effects, corporate overhead not allocated to operating functions, and the impact of the 2017 Tax Act were $607.5 million in 2017, $149.1 million in 2016 and $244.9 million in 2015.2017 vs 2016 – The net costs of Corporate activities in 2017 were unfavorable to 2016 by $458.4 million primarily due to the impact of the 2017 Tax Act, foreign exchange lossessales volumes and higher interest expense, partially offset by lower administrative expenses.The impact of the 2017 Tax Act resulted in a charge of $274.0 million principally as a result of a deemed repatriation of foreign earnings and the revaluation of deferred tax assets and liabilities.The after-tax effects of foreign currency exchange losses were $65.3 million in 2017, $117.6 million unfavorable to 2016. These effects arose due to transactions denominated in currencies other than the respective operations’ predominant functional currency. The foreign currency loss recognized in 2017 was mostly realized in Canada relating to an inter-company loan between foreign subsidiaries denominated in U.S. dollars. The Canadian operation’s functional currency is the Canadian dollar. In Malaysia, net deferred tax assets and prepaid current income tax amounts reported in its balance sheet were revalued to the Malaysian operation’s functional currency of U.S. dollars.Interest expense of $181.8 million was $33.6 million higher in 2017 as a result of bonds issued in the third quarter 2017 for net proceeds of $541.0 million. Administrative expenses associated with corporate activities were lower in 2017 by $18.9 million, primarily due to a higher allocation of costs to the exploration and production businesses. 2016 vs 2015 – The net costs of Corporate activities in 2016 were favorable to 2015 by $95.8 million mostly due to higher tax benefits and lower administrative cost, partially offset by lower 2016 benefitsrates from foreign currency exchange and higher net interest costs. Interest income was $1.1 million unfavorable in 2016 compared to 2015 due to lower average invested cash balances in Canada. The after-tax effects of foreign currency exchange were a gain of $52.3 million in 2016, $34.4 million lower than in 2015. These effects arose due to transactions denominated in currencies other than the respective operations’ predominant functional currency. The foreign currency gain recognized in 2016 was mostly realized in Canada relating to an inter-company loan between foreign subsidiaries denominated in U.S. dollars. The Canadian operation’s functional currency is the Canadian dollar. Following impairments in the prior period and lower taxable earnings, Malaysia has net deferred tax assets and prepaid current income tax amounts reported in its balance sheet. The change in income tax position in 2016 was less dramatic than 2015 and led to a lower benefit relating to income taxes in local currency. The Malaysian operation’s functional currency is the U.S. dollar. Administrative expenses associated with corporate activities were lower in 2016 by $11.7 million, primarily due to lower employee compensation expense. Depreciation expense was $4.9 million higher in 2016 compared to 2015 due to depreciation of both the new corporate building and from installation of newly acquired software.Interest expense in 2016 was $27.8 million higher than 2015 due principally to higher average interest rates in the 2016 period due to an increase of 1% on the coupon rates on $1.5 billion of the Company’s outstanding notes effective June 1, 2016 following a credit downgrade of the Company by Moody’s Investor Services in February 2016. Additionally, interest expense increased in 2016 due to issuance of $550 million of 8-year, 6.875% notes in August 2016. Total benefit for income taxes was higher in 2016 compared to 2015 by $148.6 million. The improvement in 2016 is due primarily to a U.S deferred tax charge of $188.5 million associated with a $2.0 billion distribution from a foreign subsidiary in the 2015 period.37Discontinued Operations – The Company has presented a number of businesses as discontinued operations in its consolidated financial statements. These are principally the refining and marketing operations (R&M) and the U.K. exploration and production business. The Company has accounted for these businesses as discontinued operations for all periods presented.Refining and Marketing – The Company has now transitioned to a fully independent oil and gas exploration and production company. Murphy formerly had a significant U.K. refining and marketing business. In 2014, Murphy Oil sold its U.K. retail marketing business. In 2014, the Company decided to decommission and abandon the Milford Haven, Wales refinery. The Company sold the remainder of its U.K. downstream assets in 2015. The U.K. downstream business is reported as discontinued operations for all periods presented. Loss of $0.9 million in 2017 was principally related to administrative expenses related to the legacy R&M business.The loss from R&M operations of $2.5 million in 2016 was primarily related to foreign exchange losses and administrative expenses from the legacy U.K. business.The loss in 2015 from U.K. R&M operations of $14.8 million was primarily related to loss on sale of assets, employee severance costs, legal fees and other abandonment costs related to asset closures. The Company sold the U.K. finished product terminal operations during 2015 for cash proceeds of $5.5 million.Capital ExpendituresAs shown in the selected financial data on page 24 of this Form 10-K report, capital expenditures from continuing operations, including exploration expenditures, were $975.7 million in 2017, $811.5 million in 2016 and $2.19 billion in 2015. The 2015 amount excluded capital expenditures of $0.2 million related to discontinued operations. Capital expenditures included $61.0 million, $58.5 million and $395.5 million, respectively, in 2017, 2016 and 2015 for exploration costs that were expensed.Capital expenditures for exploration and production continuing operations totaled $960.9 million in 2017, $789.7 million in 2016 and $2.13 billion in 2015.2017 – E&P capital expenditures in 2017 included $63.4 million for leases acquisition ($50.4 million for U.S. Onshore Midland basin acquisitions and $13.0 million for licenses in Brazil), $807.2 million for development drilling activities, $79.1 million for exploration activities and $11.2 million other expenditures (principally administrative and a proved property acquisition in the Gulf of Mexico). The development drilling activities were principally in the Company’s U.S. Eagle Ford Shale and Canadian Onshore (Tupper, Kaybob and Placid) businesses. Exploration activities principally included geological and geophysical (G&G) studies in Mexico, exploration drilling in Vietnam and supporting administrative costs.2016 – E&P capital expenditures in 2016 included $18.6 million for lease acquisitions principally in the U.S., $206.7 million for a property acquisition in Kaybob Duvernay and Placid Montney in Alberta, Canada, $70.1 million for exploration activities, and $494.3 million for oil and gas project developments. U.S. lease acquisitions included new leases acquired onshore and in the Gulf of Mexico. DD&A from Canadian E&P increased at Tupper Montney due to higher sales volumes and higher rates, substantially offset by lower sales volumes and lower rates at Kaybob Duvernay.38PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedExploration activities included drillingExpensesThe Company’s exploration expenses were as follows:(Millions of dollars) 2023 2022 2021 Exploration expenses Dry holes and previously suspended exploration costs $ 169.8 $ 82.1 $ 17.3 Geological and geophysical 26.1 10.4 11.8 Other exploration 28.0 27.3 21.0 Undeveloped lease amortization 10.9 13.3 18.9 Total exploration expenses $ 234.8 $ 133.1 $ 69.0 Exploration expenses in 2023 increased by $101.7 million compared to 2022. Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells in the Gulf of Mexico, Malaysia, Australiawhich encountered non-commercial hydrocarbons, and Vietnam. Additionally,the write-off of previously suspended exploration activities includedcosts for the Cholula-1EXP well in Mexico. Higher geological and geophysical expenses in 2023 relate to the purchased seismic acquisitionsdata for Côte d’Ivoire. In 2022, dry holes and previously suspended exploration costs primarily relate to expensed costs for the Cutthroat-1 exploration well in block SEAL-M-428 in offshore Brazil and the GulfTulum-1EXP exploration well in Block 5 in offshore Mexico that did not encounter commercial hydrocarbons.Other ExpensesOther expenses were $56.9 million in 2023, a decrease of Mexico and other areas,$84.9 million compared to 2022. Other expenses were lower primarily due to a lower unfavorable contingent consideration adjustment of $7.1 million in 2023 (2022: $78.3 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note O). In addition, there were lower asset retirement adjustments related to prospectsnon-producing fields of $18.2 million in Australia2023 (2022: $35.0 million).Income TaxesIncome taxes were $237.8 million in 2023, a decrease of $179.5 million compared to 2022. Lower income taxes were primarily the result of lower pre-tax income (see Note H).Corporate: 2023 vs 2022Corporate activities include interest expense and Southeast Asia. Development capital expendituresincome, 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 E&P. Realized and unrealized losses on derivative instruments would result from increases in 2016 included $226.9market oil prices relating to future periods whereby the swap contracts provided the Company with a fixed price, and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.Corporate activities reported a loss of $156.0 million in 2023, a favorable variance of $282.2 million compared to 2022. The favorable variance was primarily due to no current period losses on derivative instruments in 2023, compared to a loss for the drillingsame period in 2022 ($320.4 million) and completion program in the Eagle Ford Shale; $10.3 million for Gulflower interest expense ($38.6 million), partially offset by lower income tax benefits ($66.0 million) and foreign exchange loss of Mexico development activities including Kodiak and Dalmatian South; $118.6 million for development work in the Western Canadian Sedimentary Basin; $3.4 million for the Syncrude project; $32.3 million combined for Hibernia and Terra Nova; $3.4 million for development projects in deepwater Malaysia, including Kikeh, Kakap and Siakap; $72.4 million for oil and natural gas projects offshore Sarawak Malaysia; and $16.7 million for development of a Floating Liquified Natural Gas (FLNG) project for Block H Malaysia.2015 – E&P capital expenditures in 2015 included $12.6 million for lease acquisitions principally in the U.S., $371.9 million for exploration activities, and $1.74 billion for oil and gas project developments. U.S. lease acquisitions included acreage extensions in the Eagle Ford Shale as well as new leases acquired in the Gulf of Mexico. Exploration activities included drilling wells in the Gulf of Mexico, Malaysia, Australia and Vietnam. Additionally, exploration activities included seismic acquisitions in the Gulf of Mexico and other areas, primarily38related to prospects in Australia and Southeast Asia. Development capital expenditures in 2015 included $830.2 million for the drilling and completion program in the Eagle Ford Shale; $508.6 million for Gulf of Mexico development activities including Kodiak and Dalmatian South; $116.5 million for development work in the Western Canadian Sedimentary Basin; $23.6 million for the Syncrude project; $41.7 million combined for Hibernia and Terra Nova; $67.8 million for development projects in deepwater Malaysia, including Kikeh, Kakap and Siakap; $144.3 million for oil and natural gas projects offshore Sarawak Malaysia; and $23.8 million for development of a FLNG project for Block H Malaysia.Exploration and production capital expenditures are shown by major operating area on page 113 of this Form 10-K report.Cash FlowsOperating activities – Cash provided by operating activities of continuing operations was $1.13 billion in 2017, $600.8$10.7 million in 20162023 compared to foreign exchange gain of $23.0 million in 2022. Interest charges are lower in 2023$1.18 billion in 2015. Cash flows associated with formerly owned U.K. businesses$647.7 million during 2023 and 2022, respectively. During 2023 and as of December 31, 2023, the Company did not enter into or have been classified as discontinued operations in theany fixed price derivative swaps or collar contracts outstanding. Lower income tax benefit was a result of lower pre-tax losses.39PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedFinancial ConditionThe Company’s consolidated financial statements. Cash flowprimary sources of liquidity are cash on hand, net cash provided by continuing operations was $528.9 million higher in 2017 than in 2016 due to higher realized oilactivities and natural gas sales prices, lower lease operating expensesavailable borrowing capacity under its senior unsecured RCF. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and lower sellinginterest payments, working capital requirements, dividend payments, and, general expenses. Also, 2016 included $266.6 million relating to paymentsas applicable, share repurchases.Cash FlowsThe following table presents the Company’s cash flows for a deepwater rig contract exit.(Millions of dollars) 2023 2022 2021 Net cash provided by (required by): Net cash provided by continuing operations activities $ 1,748.8 $ 2,180.2 $ 1,422.2 Net cash required by investing activities (998.7) (1,109.4) (417.7) Net cash required by financing activities (923.7) (1,081.6) (794.5) Net cash required by discontinued operations – (14.5) – Effect of exchange rate changes on cash and cash equivalents (1.2) (3.9) 0.6 Net (decrease) increase in cash and cash equivalents $ (174.8) $ (29.2) $ 210.6 Cash flowProvided by Continuing Operations ActivitiesNet cash provided by continuing operations activities in 2023 was $582.6$431.4 million lower in 2016 than in 2015 duecompared to generally weaker crude oil2022. The decrease was primarily attributable to lower revenue from production ($661.9 million), higher payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($105.1 million) and natural gas sales prices in 2016 together with lower volume sold,timing of working capital settlements ($33.6 million), partially offset by lower leaserealized losses on derivative instruments ($535.2 million). Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements 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 expensesactivities. During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and lower severance and ad valorem taxes. $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions. See Note O for further details.The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in “Financing Activities”) during the threetwo years ended December 31, 2017, 20162023, and 20152022 were $152.5 million, $132.1$108.9 million and $117.7$150.0 million, respectively.Investing activities – Capital expenditures Lower cash interest paid in 2023 was primarily due to the early redemption, in whole or in part, of the exploration5.75% senior notes due 2025 (2025 Notes), the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and production business represent the most significant spend component7.050% senior notes due 2029 (2029 Notes) in the aggregate amount of $498.2 million.Cash Required by Investing ActivitiesNet cash required by investing activities. Propertyactivities in 2023 was $110.7 million lower compared to 2022. The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million) and lower acquisition capital ($93.0 million), partially offset by higher property additions and dry hole costs for continuing operations used cash($80.6 million).40PART IIItem 7. Management’s Discussion and $2.55 billion in 2015. CashAnalysis of $212.7 million, $695.9 millionFinancial Condition and $911.8 million was spent in 2017, 2016Results of Operations - ContinuedA reconciliation of “Property additions and 2015, respectively, to acquire Canadian government securities with terms greater than 90 days at the time of purchase. Proceeds from maturities of Canadian government securities with maturities greater than 90 days at date of acquisition were $320.8 million in 2017, $761.0 million in 2016 and $1,129.1 million in 2015. Proceeds from sales of assets generated cash of $69.5 million in 2017, $1.16 billion in 2016 and $423.9 million in 2015. The 2017 proceeds primarily relate to sale of the Seal business in Canada for $48.8 million and non-core U.S. onshore property divestments. The 2016 proceeds primarily arose due to sale of Syncrude and natural gas processing and sales pipeline assets that support natural gas fields in the Tupper area in Canada, and 2015 proceeds primarily related to sale of 10% of the Company’s oil and gas assets in Malaysia.Financing activities – During 2017 the Company issued $550 million notes in August 2017 that bear a rate of 5.75% and mature on August 15, 2025 for net proceeds of $541.6 million; these proceeds were used to redeem the Company’s $550 million 3.50% notes in September 2017. The 3.50% notes had a maturity date of December 2017 and were retired early. During 2016, the Company borrowed $541.4 million by issuing 6.875% notes maturing in 2024. The Company used $600.0 million cash during 2016 to repay long-term debt under its revolving credit facility. In 2015, the Company paid $250.0 million to repurchase 5.97 million shares, of its Common stock. Cash used for dividends to stockholders was $172.6 million in 2017, $206.6 million in 2016 and $245.0 million in 2015. The Company decreased its dividend rate by 29% in 2016 as the annualized dividend was lowered from $1.40 per share to $1.00 per share effective in the third quarter 2016. In 2017, 2016 and 2015, cash of $7.1 million, $1.1 million and $9.0 million, respectively, was used to pay statutory withholding taxes on stock-based incentive awards that vested with a net-of-tax payout.39Discontinued operations – At end of 2017, the Company’s U.K. discontinued operations had cash of $16.6 million (2016: $4.1 million; 2015: $7.9 million). This cash is classified within Current assets held for sale on the Consolidated Balance Sheet. At the end of 2017 the cash balance was $12.5 million higher than the cash balance at the end of 2016, primarily due to the collections of a previously outstanding tax receivable. At the end of 2016 the cash balance was $3.8 million lower than the cash balance at the end of 2015, primarily due to expenses related to shutdown operations. In 2015, the Company’s discontinued operations in the U.K. required $15.0 million of operating cash. The 2015 activities primarily related to the U.K. refinery and terminal operations which were sold in June 2015. In 2015, the sale of U.K. terminal assets generated cash of $5.0 million. In connection with the sales of the various U.K. assets, the Company repatriated cash from the U.K. of $184 million in 2015.Financial ConditionAt the end of 2017 working capital (total current assets less total current liabilities) amounted to $537.4 million (2016: $56.7 million; 2015: $277.4 million). Total working capital increased in 2017 primarily due to long-term debt that was classified as a current liability at the end of 2016. This 2017 maturing debt was replaced with a similar amount of long-term debt due in 2025 during 2017.Cash and cash equivalents at the end of 2017 totaled $965.0 million (2016: 872.8 million). The increase in 2017 primarily related to the conversion of Canadian government securities with maturities greater than 90 days to cash. Canadian government securities held at the end of 2016 totaled $111.5 million. These slightly longer-term Canadian investments were purchased in 2016 because of a tight supply of shorter-term securities available for purchase in Canada. Long-term debt at year-end 2017 was $483.8 million higher than year-end 2016, principally as a result of be issuance of $550 million notes in August 2017 that bear a rate of 5.75% and mature in August 2025. At the end of 2017, long-term debt represented 38.6% (2016: 33.0%) of total capital employed; the increase is principally due to the 2017 notes refinancing.Long-term debt at year-end 2016 was $617.8 million lower than year-end 2015. The decrease in debt in 2016 was primarily due to repayment of $600.0 million in debt drawn at year-end 2015 under its 2011 revolving credit facility.Stockholders’ equity was $4.62 billion at the end of 2017 (2016: $4.92 billion; 2015: $5.31 billion). Stockholders’ equity declined in 2017 primarily due to net loss incurred and cash dividends paid on its common stock. Stockholders’ equity declined in 2016 primarily due to net loss incurred and cash dividends on its common stock, partially offset by an improvement in the foreign currency translation balance due to a stronger Canadian dollar against the U.S. dollar during the year. A summary of transactions in stockholders’ equity accounts is presenteddry hole costs” in the Consolidated Statements of Stockholders’ Equity on page 64 of this Form 10-K report.Other significant changesCash Flows to total capital expenditures for continuing operations follows.Year Ended December 31, (Millions of dollars) 2023 2022 2021 Property additions and dry hole costs per cash flow statements 1$ 1,066.0 $ 985.5 $ 650.2 Geophysical and other exploration expenses 46.0 30.6 26.9 Acquisition of oil properties per the cash flow statements 135.6 128.5 20.3 Capital expenditure accrual changes and other (9.5) 38.6 (3.9) Property additions King's Quay Floating Production System (FPS) per cash flow statements – – 17.7 Total capital expenditures $ 1,138.1 $ 1,183.2 $ 711.2 1Certain prior-period amounts have been reclassified to conform to the current period presentation.Total accrual basis capital expenditures are shown below.Year Ended December 31, (Millions of dollars) 2023 2022 2021 Capital Expenditures Exploration and production $ 1,114.0 $ 1,161.5 $ 690.1 Corporate 24.1 21.7 21.1 Total capital expenditures 1,138.1 1,183.2 711.2 Total capital expenditures excluding proved property acquisitions 1,111.0 1,054.7 711.2 Total capital expenditures excluding proved property acquisitions and NCI $ 1,040.8 $ 1,028.8 $ 688.2 Lower capital expenditures in Murphy’s balance sheet2023 compared to 2022 were primarily attributable to lower development expenditures at the end 2017, compared to 2016 are discussed below.Deferred income tax assets decreased $154.4 million to $211.5 million (2016: $365.9 million) principally as a result of the impact of the 2017 Tax Act which resulted in the revaluation of deferred tax assets to the newly enacted U.S. federal tax rate of 21% (prior to the 2017 Tax Act: 35%).Deferred income tax liabilities increased $90.0 million to $159.1 million (2016: $69.1 million) principally as a result of current year Canadian taxable profits utilizing prior taxable losses and the change from a U.S. net deferred tax asset position to a net deferred tax liability position, due in part, to withholding tax liability recorded on $1.3 billion of foreign earnings no longer indefinitely reinvested.Liabilities associated with assets held for saleKhaleesi, Mormont, Samurai field development project, lower spend at the end of 2016 relatedKodiak and Lucius fields and lower acquisition capital, partially offset by higher exploratory drilling and higher development expenditures at the Dalmatian and St. Malo fields. Capital expenditures in 2023 primarily relate to field abandonment for the Seal field in Canada that was sold in January 2017.Murphy had commitments for future capital projects of approximately $432.3 million at December 31, 2017 (2016: $585.7 million). These commitments included $197.3 million fordevelopment drilling and field development and future work in Malaysia, $129.4 million for development at Kaybob Duvernay in Canada, $31.8 million for workactivities in the Eagle Ford Shale $31.3 million($361.5 million); development activities in the Gulf of Mexico, primarily related to St. Malo, Dalmatian, Samurai and Marmalard fields ($310.1 million); development drilling and field development activities at the Tupper Montney field ($142.0 million); field development at Terra Nova for the asset life extension project ($44.7 million); and total exploration incosts of $214.3 million. Exploration costs were primarily for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico and $8.8activities at Côte d’Ivoire. Costs of $169.8 million primarily associated with Chinook #7 (Walker Ridge 425) and $6.3Oso #1 (Atwater Valley 138) were expensed to dry hole costs in 2023 as the Company determined there were non-commercial hydrocarbons present.Cash Required by Financing ActivitiesNet cash required by financing activities in 2023 decreased by $157.9 million compared to 2022. In 2023, cash used in financing activities was principally for future work commitments offshore Vietnam and Brunei, respectively.The primary sourcesthe redemption of the Company’s liquidity are internally generated funds, accessremaining $248.7 million principal outstanding on its 2025 Notes and the tendering of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes. In addition, the Company repurchased common shares ($150.0 million, excluding accrued excise tax), paid contingent consideration related to outside financingprior Gulf of Mexico acquisitions ($60.2 million) as discussed in the ‘Cash Provided by Continuing Operating Activities’ section, paid cash dividends to shareholders of $1.10 per share ($171.0 million), and working capital. The Company generally uses its internally generateddistributed funds to finance its capitalthe noncontrolling interest in the Gulf of Mexico ($29.4 million).41PART IIItem 7. Management’s Discussion and operating expenditures, but it also maintains linesAnalysis of credit with banksFinancial Condition and will borrow as necessary to meet spending requirements. Results of Operations - ContinuedLiquidityAt December 31, 2017,2023, the Company has ahad approximately $1.1 billion of liquidity consisting of $317.1 million in cash and cash equivalents and $796.2 million available on its committed senior unsecured guaranteed credit facility (2016 facility)RCF with a major banking consortium, which nowconsortium.The Company’s $800 million senior unsecured RCF expires in August 2021. AtNovember 2027 and as of December 31, 2017,2023, the402016 facility; however, there were $90.7RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. Advancessenior unsecured RCF. Borrowings under the 2016 facility will accrueRCF are subject to certain interest based, atrates, please refer to Company’s option,interest rate in effect 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 borrowedborrowings under the 2016 facility at December 31, 2017, the applicable base interest rate would have been 4.875%7.70%. At December 31, 2017,2023, the Company was in compliance with all covenants related to the 2016 facility.On November 17, 2017, the Company entered into the third amendment (Amendment No. 3) to its 2016 facility with, among other parties, JPMorgan Chase Bank, N.A., as administrative agent. Amendment No. 3 extended the maturity date of the Credit Agreement to August 17, 2021, reduced the facility fee on revolving commitments and the interest margin on revolving loans. Amendment No. 3 also limited the consolidated net debt to no more than 4.00 times the last twelve months (LTM) Adjusted EBITDAX. Other covenants include a minimum Adjusted EBITDAX for the LTM of 2.5 times LTM consolidated interest expense, and minimum liquidity from U.S. and other certain subsidiaries equal to or greater than $500 million. Also beginning March 31, 2017, if the Company’s total leverage ratio exceeds 3.50 times the Company’s LTM Adjusted EBITDAX, the facility will become secured, subject to limitations set forth in the Company’s existing notes. 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 $8.4 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 was paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 3.50% notes in September 2017. The $550 million 3.50% 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 originally expired in August 2019, and has subsequently been extended to mature in August 2021. 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 has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. In 2017 the Company’s earnings covered fixed charges 1.4 times. In 2016 and 2015 the Company’s earnings were inadequate to cover fixed charges by $477.0 million and $3.3 billion, respectively.Cash and invested cash are maintained in several operating locations outside the United States. AtU.S. As of December 31, 2017,2023, cash and cash equivalents held outside the U.S. included $549.3U.S dollar equivalents of approximately $148.9 million (2016: $210 million, including cash temporarily invested in Canadian government securities with greater than 90 day maturities)(2022: $147.7 million), the majority of which was held in Canada ($105.2 million) and $334.6 million (2016: $262Mexico ($18.1 million) in Malaysia.. In addition, approximately $16.6$9.6 million and $8.3 million of cash was held in the U.K. and has been classified as part of Assets held for sale in the Consolidated Balance Sheets at year-end 2017.Spain, respectively. 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. Canada currently collects a 5% withholding tax on any cashearnings repatriated to the U.S. See Note I of the consolidated financial statements H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United StatesStates.Working Capital(Millions of dollars) December 31, 2023 December 31, 2022 Working capital Total current assets $ 752.2 $ 972.3 Total current liabilities 846.5 1,257.8 Net working capital liability $ (94.3) $ (285.5) As of December 31, 2023, net working capital had a favorable increase of $191.2 million compared to December 31, 2022. The favorable increase was primarily attributable to lower other accrued liabilities ($302.8 million) and lower accounts payable ($96.9 million), partially offset by lower accounts receivable ($47.2 million) and a lower cash balance ($174.9 million). Lower accrued liabilities were primarily due to payments made for contingent consideration obligations from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made in 2023. Lower accounts payable were primarily due to decreases in unrealized losses on derivative instruments (commodity price swaps and collars), decreases in royalties payable due to lower revenues, payments made for abandonment activities and drilling and completions activities. Lower unrealized losses on derivative instruments were as a result of no commodity derivative instrument contracts entered into or outstanding during 2023. Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas liquids and lower pricing received for all crude oil, natural gas liquids and natural gas.4142PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedCapital EmployedA summary of capital employed as of December 31, 2023 and 2022 follows.December 31, 2023 December 31, 2022 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 1,328.4 19.9 % $ 1,822.4 26.7 % Murphy shareholders' equity 5,362.8 80.1 % 4,994.8 73.3 % Total capital employed $ 6,691.2 100.0 % $ 6,817.2 100.0 % As of December 31, 2023, long-term debt decreased by $494.0 million compared to December 31, 2022, as a result of the redemption and early redemption of, in whole or in part, the 2025 Notes, 2027 Notes, 2028 Notes, and 2029 Notes. The fixed-rate notes had a weighted average maturity of 8.1 years and a weighted average coupon of 6.2%.Murphy’s shareholders’ equity increased by $368.0 million in 2023 primarily due to net income earned ($661.6 million), partially offset by cash dividends paid ($171.0 million) and shares repurchased ($150.0 million, including excise tax). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 69 of this Form 10-K report.Other Balance Sheet Activity - Long-Term Assets and LiabilitiesOther significant changes in Murphy’s balance sheet at the end of 2023, compared to 2022 are discussed below.Property, plant and equipment, net of depreciation, decreased $2.8 million principally due to DD&A expense ($861.6 million) and divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, substantially offset by capital expenditures in the year and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the ‘Cash Required for Investing Activities’ section.Murphy had commitments for capital expenditures of approximately $209.8 million at December 31, 2023 (2022: $282.4 million). This amount includes $75.1 million for approved expenditures for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St. Malo ($61.7 million), non-operated Canada interests, mainly offshore ($11.6 million), non-operated Lucius ($13.3 million) and non-operated Eagle Ford Shale ($11.8 million).Operating lease assets decreased $201.2 million principally due to depreciation on these assets.Deferred Income tax assets decreased by $117.5 million as a result of the decrease in the U.S. net operating loss carryforward from $2.1 billion at year-end 2022 to $1.7 billion at year-end 2023.Long term asset retirement obligations increased $86.8 million primarily due to accretion and additions and revisions related to Gulf of Mexico and Eagle Ford Shale operations.Non-current operating lease liabilities decreased $190.8 million primarily due to 2023 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.Deferred income tax liabilities increased $61.7 million due to capital related tax deductions.43PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedOther Key Performance MetricsThe Company uses other operational performance and income metrics to review operational performance. Management uses adjusted net income, EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income also excludes certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA and are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.Year Ended December 31, (Millions of dollars) 2023 2022 2021 Net income attributable to Murphy (GAAP) 1$ 661.6 $ 965.0 $ (73.7) Discontinued operations loss 1.5 2.1 1.2 Net income from continuing operations attributable to Murphy 663.1 967.1 (72.5) Adjustments 2:Write-off of previously suspended exploration wells 17.1 22.7 – Asset retirement obligation losses (gains) 16.9 30.8 (71.8) Foreign exchange loss (gain) 10.9 (23.0) (1.0) Mark-to-market loss on contingent consideration 7.1 78.3 63.2 Mark-to-market (gain) loss on derivative instruments – (214.7) 112.1 (Gain) on sale of assets – (14.5) – Early redemption of debt cost – 10.3 43.9 Impairment of assets – – 196.3 Tax benefits on investments in foreign areas – – (8.9) Charges related to Kings Quay transaction – – 4.9 Unutilized rig charges – – 8.7 Total adjustments, before taxes 52.0 (110.1) 347.4 Income tax (benefit) expense related to adjustments (6.4) 23.8 (75.2) Total adjustments after taxes 45.6 (86.3) 272.2 Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 708.7 $ 880.8 $ 199.7 Net income from continuing operations per average diluted share (GAAP) $ 4.23 $ 6.14 $ (0.47) Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 4.52 $ 5.59 $ 1.29 1 Excludes amounts attributable to a noncontrolling interest in MP GOM.2 Certain prior-period amounts have been reclassified to conform to the current period presentation.44PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedThe following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.Year Ended December 31, (Millions of dollars) 2023 2022 2021 Net (loss) income attributable to Murphy (GAAP) 1$ 661.6 $ 965.0 $ (73.7) Income tax expense 195.9 309.5 (5.9) Interest expense, net 112.4 150.8 221.8 Depreciation, depletion and amortization expense 2836.7 748.2 760.6 EBITDA attributable to Murphy (Non-GAAP) 1,806.6 2,173.5 902.8 Accretion of asset retirement obligations 241.0 40.9 41.1 Write-off of previously suspended exploration well 17.1 22.7 – Asset retirement obligation loss (gain) 16.9 30.8 (71.8) Foreign exchange loss (gain) 10.8 (23.0) (1.0) Mark-to-market loss gain on contingent consideration 7.1 78.3 63.2 Mark-to-market (gain) loss on derivative instruments – (214.7) 112.1 Discontinued operations loss 1.5 2.1 1.2 Gain on sale of assets 2– (14.5) – Impairment of assets 2– – 196.3 Unutilized rig charges – – 8.7 Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,901.0 $ 2,096.1 $ 1,252.6 1 Excludes amounts attributable to a noncontrolling interest in MP GOM.2 Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDA exclude the portion attributable to the noncontrolling interest.45PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedEnvironmental, Health and Safety MattersMurphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmentenvironmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system with appropriateincorporating oversight at theeach business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and maintenance,implementation of a comprehensive asset integrity plan, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and major risks it identifies through impact assessments.Murphyapproved by a Health, Safety, Environment and other companies inCorporate Responsibility Committee consisting of certain members of the Board.The oil and gas industry areis subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations. Murphy allocates a portion of both its capital expenditure program, as well asexpenditures and its general and administrative budget to complytoward compliance with existing and anticipated environmental, health and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities andas well as operating costs for ongoing compliance.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,materials; the emission and discharge of such materials to the environment, greenhouse gas emissions,including GHG emissions; wildlife, habitat and water protection andprotection; the placement, operation and decommissioning of production equipment.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. Any violation of applicable environmental laws, regulations or permitsoperations and the decommissioning facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays,delays.Further information on environmental, health and other sanctions. Thesesafety laws and regulations and permits have been subjectapplicable to frequent change and tend to become more stringent over time. The changeMurphy are contained in the federal administration creates uncertaintyClimate Change and EmissionsThe world’s population and standard of living is growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of GHG, which could raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in future changes as well asorder to remain in alignment with the enforcementTCFD core elements. The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of existing laws and regulations.climate-related financial information. Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2023 Sustainability Report issued on August 2, 2023, which is not incorporated by reference hereto.Other MattersImpact of inflation – In the United States, the Environmental Protection Agency has implemented requirements2023, many countries worldwide continued to reduce sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations,experience a rise in inflation, including standards for wells that are hydraulically fractured. Any current or future air emission or other environmental requirements applicable to Murphy’s businesses could curtail its operations or otherwise result in operational delays, liabilities and increased costs.Certain jurisdictions in whichcountries where the Company operates have required, or are considering requiring, more stringent permitting, chemical disclosure, transparency, water usage, disposal and well construction requirements. Regulators are also becoming increasingly focused on air emissions from(this follows a sustained period of relatively low inflation prior to 2021). In the oil and gas industry, including volatile organic compound and methane emissions.Murphy also could be subject to strict liability for environmental contamination, in various jurisdictions where we operate, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors. Contamination has been identified at certain of such sitesU.S., inflation continued as a result of which the Company has been requiredongoing supply constraints and in the future may be required to remove or remediate previously disposed wastes, clean up contaminated soil, surface water and groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations. In addition to significant investigation and remediation costs, such matters can result in fines and also give rise to third-party claims for personal injury and property or other environmental damage.In early 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The Company has retained these liabilities following the sale of the Seal business in January 2017. Following the spill, 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 continues to progress as planned and the Company’s insurers were notified. Based on the assessments done to date, the Company recorded $43.9 million in Other expense in the 2015 Consolidated Statements of Operations associated with the estimated costs of remediating the site. The Company has spent $39.7 million from inception to the end of 2017. Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible fines from regulators. In the first quarter 2018, the Company received $15.0 million in respect to an insurance claim regarding this matter and the outcome of further claims are pending.Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were approximately $13 million in 2017 (2016: $13 million). This spending is projected to be approximately $15 million in 2018.42Climate ChangeMurphy is currently required to report greenhouse gas emissions from certain of its operations and, in British Columbia and Alberta, is subject to a carbon tax on the purchase or use of many carbon-based fuels. Additionally, starting in 2017, a carbon tax applies to certain operations in Alberta. The Canadian Government has announced a proposal that all other provinces and territories implement some form of carbon pricing by 2018. Any limitation on or further regulation of, greenhouse gases (including through a cap and trade system) technology mandate, emissions tax, reporting requirement or other program, could restrict the Company’s operations, curtailincreasing demand for hydrocarbons generally and/or impose increased costs, including to operategoods and maintain facilities, install pollution emission controls and administer and manage emissions trading programs.Safety MattersThe Company is subject toservices as countries continue their recovery from the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in Murphy’s operations and that this information be provided to employees, state and local government authorities and citizens.COVID-19 pandemic. The Company believes that its operations are in substantial compliance with applicable safety requirements, including general industry standards, record-keeping requirements and the monitoring of occupational exposure to regulated substances.Other MattersImpact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues, and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas industry and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPECOPEC+ production levels and/or attitudes of traders concerning supply and demand in the near future. PricesCosts for oil field goods and services are usually affected by the worldwide prices for crude oil.OilTo combat impacts of inflation and/or supply and gas prices are generally driven by fundamental demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply factorschain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for hydrocarbons,rigs46PART IIItem 7. Management’s Discussion and as such, as demandAnalysis of Financial Condition and supply factors shift, oil Results of Operations - Continuedand gas prices also shift. Priorother industry services which could expose Murphy to the dropimpact of higher costs. Murphy continues to strive toward safely executing our work in oil pricesan ever-increasing efficient manner to mitigate possible inflationary pressures in late 2014, the cost for oil field materials and services had generally risen in the preceding years. In 2015-2016 lower oil prices reduced the demand for oil and gas materials and services, which led to significant downward pressure on the cost of these materials and services in 2015 and 2016. In 2017, as oil and gas prices have moved higher, drilling activity has begun to increase, leading to an upward pressure on the cost of oil and gas materials and services. our business.Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas is generallycan be restricted to specific geographic areas. In 2015Natural gas demand is also impacted by demand driven by lower carbon emissions and 2016 North Americana view that natural gas prices also moved lower, as a result of abundant supply. As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.Critical Accounting changes and recent accounting pronouncementsAccounting Principles AdoptedCompensation – Stock Compensation. In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (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.Business Combinations. In January 2017, the FASB issued an 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 and43processes 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.Recent Accounting PronouncementsRevenue from Contracts with Customers. In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Company has performed a review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of the ASU. As a result of this review, the Company’s gross revenues and expenses may be impacted based on the determination of whether it is acting as a principal or an agent in certain transactions. The Company adopted the new standard on January 1, 2018, using the modified retrospective method and does not currently expect net earnings, revenues or expenses to be materially impacted. The Company continues to evaluate the impact of this and other provisions of the ASU on related disclosures. Leases. In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.Statement of Cash Flows. In 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 anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolidated financial statements.Compensation – Retirement Benefits. In 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. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolidated financial statements.Compensation – Stock Compensation. 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. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolidated financial statements.44Significant accounting policiesEstimates U.S. GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.Oil and natural gas proved reserves– Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain). Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use aan unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas priceprices and reserve assumptions when making its own internal economic property evaluations. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities. Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including:including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods. The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 106103 to 112 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high-degreehigh degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog basedanalog-based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, andestimates. It was utilized in certain undrilled acreage at distances47PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continuedgreater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 20172023 beginning on pages 74 and 107103 of this Form 10-K report.ImpairmentProperty, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property,“Property, plant and equipment (PPE)equipment” in the Consolidated Balance Sheet to make sureensure that they are fairly presented. The Company must evaluate its PPEproperty, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the45The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment. Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections. Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. Based on a review of realized sales prices and costs, estimated futures prices for oil and natural gas, estimates of reserves and relevant regulator environments, the company did not record any impairment expenseThere were no impairments recognized in 2017.The Company recorded impairment expense of $95.1 million in 2016 to reduce the carrying value of producing heavy oil properties in Western Canada and the Terra Nova field offshore Canada to their estimated fair value due to significant declines in future oil prices in early 2016.The Company recorded impairment expense of $2,493.2 million in 2015 to reduce the carrying value of producing offshore properties in Malaysia, producing heavy oil properties in Western Canada and producing and non-producing properties in the Gulf of Mexico to their estimated fair value due to significant declines in future oil and gas prices during 2015. 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.Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the CompanyCompany; and (d) changes to regulationregulations may be subject to interpretation or claritydifferent interpretations and require future clarification from issuing authorities. authorities or others.The Company has deferred tax assets mostly relating to basis differences for property, equipment and inventories, andU.S net operating losses, liabilities for dismantlement, and retirement benefit plan obligations and net deferred tax liabilities relating to U.S.tax and accounting basis differences for property, equipmentplant and inventories. equipment.The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization.On December 22, 2017, the U.S. enacted into legislation the Tax Cutsrealization and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, the Company recorded tax expense of $274.0 million directly relatedreduce such assets to the impactsexpected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the 2017 Tax Act. The charge includes the impact of a deemed repatriation of historic foreign earnings and the re-measurement of deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and liabilities. Separately, Murphy expects to receive cash refunds or creditsnegative evidence. Positive evidence includes projected future taxable income and assessment of $29.7 million overfuture business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.48PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedAs of December 31, 2023 the next four years relating to Alternative Minimum Tax (AMT) credits generated in earlier years. Murphy continues to assess the impact of this legislation including, among other things, the carry-forward of 2017Company had a U.S. deferred tax asset associated with net operating losses refinement of post-1986 accumulated foreign earnings$357.5 million. In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and profits computations, the change to U.S. federal tax rates, the possible limitations on the deductibility of interest expense, the option for expensing of capital expenditures, the migration from a worldwide system of taxation to a territorial system, and the use of new anti-base erosion provisions. The tax expense recorded in 2017 is a reasonable estimatefuture taxable income estimates based on published guidanceprojected financial information which, based on currently available at this timeevidence, we believe to be reasonably likely to occur. Certain estimates and considered provisional. The ultimate impactassumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the 2017 Tax Act may differ from these estimates due to changes in interpretations and assumptions made by the company, as well as additional regulatory guidance that may be issued. The Company’s statutory U.S. tax rate will be 21% beginning in 2018, a decrease from the previous ratefuture utilization of 35%. our net operating loss carryforwards.46 Oil and certain of its subsidiaries maintain defined benefit retirement plans covering mostcertain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is determinedestimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.Based on bond yields atas of December 31, 2017,2023, the Company has used a weighted average discount rate of 3.7%5.15% at year-end 20172023 for the primary U.S. plans. This weighted average discount rate is 0.6%0.3% lower than aprior year, earlier, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. Although theThe Company presently assumesassumed a return on plan assets of 6.50%8.00% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 20182024 are expected to be $3.0$0.7 million higher than 2017in 2023 primarily due to higher amortization of actuarial lossesthe increase in the benefit obligations at year-end 2017.December 31, 2023 compared to the prior year, which increases the interest cost recognized in net periodic benefit costs. Cash contributions to all plans are anticipated to be $3.2$2.9 million higher in 2018. 2024. In 2017,2023, the Company paid $24.9$37.5 million into various retirement plans and $2.4$2.0 million into postretirement plans. In 2018,2024, the Company is expecting to fund payments of approximately $25.1$38.0 million into various retirement plans and $5.4$4.4 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected. As described above,Recent Accounting PronouncementsSee Note B in our Consolidated Financial Statements regarding the Company’s retirementimpact or potential impact of recent accounting pronouncements upon our financial position and postretirement expenses are sensitive to certain assumptions, primarily related to discount ratesresults of operations.49PART IIItem 7. Management’s Discussion and assumed return on plan assets. A 0.5% decline in the discount rate would increase 2018 annual retirement expenses by $0.7 millionAnalysis of Financial Condition and decrease postretirement expenses by $0.1 million; and a 0.5% decline in the assumed rateResults of return on plan assets would increase 2018 retirement expense by $2.8 million.Legal, environmental and other contingent matters – A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company.47commitments,plans and other long-term liabilities. In addition, the Company expects to extend certain operating leases beyond the minimum contractual period. Total payments due after 20172023 under such contractual obligations and arrangements are shown in the table below.2,916.4 9.9 21.4 1,117.4 1,767.7 317.3 73.7 128.0 89.1 26.5 1,596.3 332.6 363.1 173.0 727.6
interest2,617.8 197.4 325.8 371.4 1,723.2 7,447.8 613.6 838.3 1,750.9 4,245.0 (Millions of dollars) Amount of Obligations Total 2024 2025 - 2026 2027 - 2028 After 2028 Debt, excluding interest $ 1,334.9 $ – $ – $ 815.4 $ 519.5 Operating leases and other leases ¹ 1,019.3 245.7 148.4 125.4 499.8 Capital expenditures, drilling rigs and other ² 1,289.6 434.4 264.2 197.9 393.1 Other long-term liabilities, including debt interest ³ 2,379.0 98.9 197.6 139.4 1,943.1 Total $ 6,022.8 $ 779.0 $ 610.2 $ 1,278.1 $ 3,355.5 2 Capital expenditures, drilling rigs and other includes $51.6 million, $11.8 million, $11.6 million and $4.0 million, in 2024 for approved capital projects in non-operated interests in U.S. Gulf of Mexico, U.S. Onshore, Canada Offshore and Other Foreign Offshore, respectively. Capital expenditures, drilling rigs and other includes $23.5 million in 2025 for approved capital projects in non-operated interests in U.S. Gulf of Mexico.Also includes $74.6 million (2024), $145.3 million (2025 - 2026), $140.2 million (2027 - 2028) and $308.1 million (After 2028) for pipeline transportation commitments in Canada.Also includes $4.1 million (2024), $7.7 million (2025 - 2026), $7.7 million (2027 - 2028) and $22.5 million (After 2028) for long term take or pay commitments relating to natural gas processing in Canada.3 Other long-term liabilities, including debt interest, includes future cash outflows for asset retirement obligations.The Company has entered into agreements to lease production facilities for various producing oil fields. In addition, the Company hasfields as well as other arrangements that call forrequire future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.In 2013, the Company entered into a 25-year lease for a semi-floating production system at the Kakap field offshore Sabah, Malaysia. The Company has included the required net lease obligations for this production system as Debt in the contractual obligation table above.In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $179.7$200.6 million as of December 31, 2017.Material off-balance sheet arrangements – The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2017 included operating leases of floating, production, storage and offloading vessel (FPSO) for the Kikeh oil field, drilling contracts for onshore and offshore rigs in various countries, and oil and/or natural gas transportation and processing contracts in the U.S. and Western Canada. The leases call for future monthly net lease payments through 2022 at Kikeh. TheCertain U.S. transportation contracts require minimum monthly payments through 2024,2045, while WesternOnshore Canada transportation and processing contracts call for minimum monthly payments through 2035.2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above. In February 2016, FASB issued an ASU to increase transparency50PART IIItem 7. Management’s Discussion and comparability among companiesAnalysis of Financial Condition and Results of Operations - ContinuedOutlookThe oil and gas industry is impacted by recognizing lease assetsglobal commodity pricing and lease liabilities onas a result the balance sheet and disclosing key information about leasing arrangements. The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.OutlookPricesprices for the Company’s primary products are often quite volatile. The price for crude oil is primarily affectedvolatile aAnticipated future variances betweenAs discussed in the predicted demandResults of Operations section discussing revenues, on page 37, lower average crude oil price during in 2023 directly impacted the Company’s product sales revenue.As of close on February 21, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:2024 2025 WTI ($/BBL) 75.63 70.84 NYMEX ($/MMBTU) 2.41 3.38 AECO (US$ Equivalent/MCF) 1.39 2.38 In 2023, liquids from continuing operations represented approximately 60% of total hydrocarbons produced on an energy equivalent basis. In 2024, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%. If the prices for crude oil and natural gas are lower in 2024 or beyond, this will have an unfavorable impact on the projected available supply can leadCompany’s operating profits; likewise, if prices are higher, this will have a favorable impact. The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.The Company currently expects average daily production in 2024 to be between 187,100 and 195,100 barrels of oil equivalent per day (including noncontrolling interest of 7,100 BOEPD). If significant movementprice declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.Similar to the overall inflation and higher interest rates in the price of crude oil. In January 2018, West Texas Intermediate crude oil averaged about $64 forwider economy, the month and averaged $62 in the first three weeks of February. NYMEX natural gas averaged $3.72 during January 2018. Both of these oil and natural gas industry and the Company are observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.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, are above the average prices achievedshould they occur, will result in 2017. The Company continually monitors the prices for its main productslower profits and often alters its operations and spending plans based on these prices.The Company’s capital expenditure budgetspend for 20182024 is expected to be $1.06 billion which assumes a West Texas Intermediate oil price of $52 per barrelbetween $920 million and Henry Hub natural gas price of $3.00 per thousand cubic feet. Approximately 62% of the total capital is being allocated towards the onshore unconventional businesses with a majority at Eagle Ford Shale. Offshore development expenditures are focused on short-cycle projects that maintain existing assets and other activities expected to increase value-added production in future years. Approximately 10% of the annual budget has been allocated for exploration activities.$1,020 million, excluding noncontrolling interest. Capital and other expenditures will beare routinely reviewed during 2018 and planned capital expenditures may be adjusted to reflect48actualforecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 20182024 using operating cash flow and available cash, but will supplement funding where necessary using borrowings under available credit facilities.cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that further capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.The Company currently expects average daily production in 2018plans to utilize surplus cash (not planned to be between 164,000used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and 168,000 barrelsdebt reduction. Details of oil equivalent per day. North American onshore unconventional production is expectedthe framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022. During 2023, the Board authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be 56%repurchased under the program to $600 million. As of 2018 production.The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F).51PART IIItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - ContinuedAs of February 21, 2024, the Company has entered into WTI crude oil swap contracts and natural gas forward fixed-price delivery contracts to manage risk associated with certain U.S. crudefuture oil and Canadian natural gas sales prices as follows:Volumes
(MMcf/d)Price/MCF Remaining Period Area Commodity Contract orType Start Date AverageEnd Date CommoditiesNatural Gas LocationFixed price forward sales 162 DatesC$2.39 1/1/2024 Volumes per DayAverage Prices12/31/2024 U.S. OilNatural Gas West Texas IntermediateFixed price forward sales 25 Jan. 2018 – Dec. 2018US$1.98 1/1/2024 21,000 bbls/d$54.88 per bbl.10/31/2024 Canadian CanadaNatural Gas Fixed price forward sales TCPL–NOVA System15 US$1.98 Jan. 2018 – Dec. 202011/1/2024 59 mmcf/dC$2.81 per mcfCanadian Natural GasChicago GateJan. 2018 – Dec. 201820 mmcf/dUS$3.51 per mcf12/31/2024 In 2017 the Company observed upward pressure on the cost for oil field goods and services as commodity prices increased. This follows price concessions from many of its vendors that supplied oil field goods and services in 2015 and 2016 during lower commodity prices.Forward-Looking StatementsThis Form 10-K 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 theseby 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; geopolitical concerns; 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, including inflation. 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 Item 1A. Risk Factors, which begins on page 1315 of this Annual Report on Form 10-K. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.statements.4952Item 7A. 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 and interest rates. As described in Note L,K, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.There were commodity transactionsno outstanding crude oil derivative contracts as of December 31, 2023.There were no derivative foreign exchange contracts in place atas of December 31, 2017 covering certain future U.S. crude oil sales volumes in 2018. A 10% increase in the respective benchmark price2023.At December 31, 2023, long-term debt was $1,328.4 million. The fixed-rate notes have a weighted average coupon of these commodities would have increased the recorded net liability associated with these derivative contacts by approximately $45.5 million, while a 10% decrease would have decreased the recorded net liability by a similar amount.Item 8. FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATAInformation required by this item appears on pages 5765 through 118120 of this Form 10-K report.Ite53PART IIItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREItem 9A. CONTROLS AND PROCEDURESUnder the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy 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 their evaluation, with the participation of the Company’s management, as of December 31, 2017,2023, 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) were 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.Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2017. Management’s report is included on page 57 of this Form 10-K report.2023. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20172023 and their report is included on page 5964 of this Form 10-K report.There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 20172023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.Item 9B. OTHER INFORMATIONDuring the three months ended December 31, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONSNone5054Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCECertain information regarding executive officers of the Company is included on page 2129 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 20188, 2024 under the captions “Election of Directors” and “Committees.“The Board and Committees.”Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’sCorporate Secretary at P.O. Box 7000, El Dorado, AR 71731-7000.9805 Katy Fwy, Suite G-200, Houston, TX 77024. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s Website.Item 11. EXECUTIVE COMPENSATIONInformation required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 20188, 2024 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors”“How We Are Compensated” and in various compensation schedules.ItAs required by U.S federal securities laws, the Company revised its incentive-based compensation recoupment (clawback) policy providing for the recovery of erroneously awarded incentive-based compensation received by current or former executive officers. We have filed our written recoupment policy as Exhibit 10.29em to this Form 10-K report and as of December 31, 2023, there have been no accounting restatements requiring compensation recoupment.Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSInformation required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 20188, 2024 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,”caption “Our Stockholders” and in the “Equity Compensation Plan Information.”Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEInformation required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 20188, 2024 under the caption “Election of Directors.”Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICESOur independent registered public accounting firm is KPMG LLP, Houston, TX, Auditor Firm ID: 185.Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 20188, 2024 under the caption “Audit Committee Report.”Report”.5155Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES(a) 1. Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.57 57 (KPMG LLP , Houston, TX, Auditor Firm ID: 185)58 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting(KPMG LLP, Houston, TX, Auditor Firm ID: 185)59 60 61 62 63 64 65 104 118 2. Financial Statement SchedulesAll other financial statement schedules are omitted because either they are not applicable, or the required information is included in the consolidated financial statements or notes thereto.56PART IV3. Exhibits – The 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 either are not required or are not applicable.
No.No.
Murphy Oil Corporation2.1 Exhibit 2.1 to Form 8-K filed June 5, 2019 3.1Exhibit 2.2 to Form 8-K filed June 5, 2019 2.3 Exhibit 2.1 to Form 10-K filed February 27, 2019 2.4 Exhibit 10.3 to Form 10-Q filed May 2, 2019 3.1 of Murphy’sto Form 10-K report filed February 28, 20113.2 3.2of Murphy’sto Form 8-K report10-Q filed February 5, 20164.1 52ExhibitNo.Incorporated by Reference to4.1of Murphy’sto Form 10-K report for the year ended December 31, 20094.2 Exhibit 4.2 to Form 10-K filed March 16, 2005 4.2ExhibitsExhibit 4.1 and 4.2 of Murphy’sto Form 8-K report filed May 18, 20124.4 4.3of Murphy’sto Form 8-K report filed November 30, 2012.4.5 4.4Exhibit 4.1 of Murphy's Form 10-Q report filed August 5, 20144.5Commitment Increase and Maturity Extension Agreement dated May 23, 2013Exhibit 4.2 of Murphy's Form 10-Q report filed August 5, 20144.6of Murphy'sto Form 8-K report filed August 17, 20164.6 4.7Exhibit 4.1 to Form 8-K filed August 18, 2017 4.7 4.1 of Murphy’s4.2 to Form 8-K report filed August 18, 20174.8 Exhibit 4.9 to Form 10-K filed February 27, 2020 10.1Exhibit ASixth Supplemental Indenture dated as of Murphy’s definitive Proxy Statement (Definitive 14A) dated March 29, 201210.2Exhibit 10.3 of Murphy’s Form 10-K report for the year ended December 31, 201210.32008 Stock Plan for Non-Employee Directors, as approved by shareholders on May 14, 2008Form S-8 report filed February 5, 200910.4Exhibit A of Murphy’s definitive Proxy Statement (Definitive 14A) dated March 22, 201310.5Non-Qualified Deferred Compensation Plan for Non-Employee DirectorsExhibit 10.6 of Murphy's Form 10-K report for the year ended December 31, 201510.610.1 of Murphy’s4.2 to Form 8-K report filed SeptemberMarch 5, 201310.1 10.7Exhibit 10.3 of Murphy’s Form 8-K report filed September 5, 201310.8Exhibit 10.4 of Murphy’s Form 8-K report filed September 5, 201353ExhibitNo.Incorporated by Reference to10.10Exhibit 10.2 of Murphy's Form 8-K report filed August 12, 201610.1157PART IV10.2 Exhibit 10.3 to Form 10-K filed February 25, 2022 10.3 Exhibit A to definitive proxy statement filed March 29, 2012 10.4 Exhibit 10.8 to Form 10-K filed February 27, 2020 10.5 Exhibit 99.1 to Form 10-K filed February 28, 2014 10.6 Exhibit 99.3 to Form 10-Q filed May 7, 2014 10.7 Exhibit B to definitive proxy statement filed March 23, 2018 10.8 Exhibit 10.15 to Form 10-K filed February 27, 2020 10.9 Exhibit 10.14 to Form 10-K filed February 27, 2019 10.10 Exhibit 10.17 to Form 10-K filed February 27, 2020 10.11 Exhibit 10.15 to Form 10-K filed February 27, 2019 10.12 Exhibit 10.16 to Form 10-K filed February 27, 2019 10.13 Exhibit A to definitive proxy statement filed March 30, 2020 10.14 Exhibit 10.21 to Form 10-K filed February 26, 2021 10.15 Exhibit 10.22 to Form 10-K filed February 26, 2021 10.16 Exhibit 10.23 to Form 10-K filed February 26, 2021 10.17 Exhibit 10.24 to Form 10-K filed February 26, 2021 10.18 Exhibit 10.25 to Form 10-K filed February 26, 2021 10.19 Exhibit A to definitive proxy statement filed March 23, 2018 10.20 Exhibit 10.1 to Form 8-K report filed November 20, 2017April 25, 201810.21 Exhibit 10.24 to Form 10-K filed February 27, 2020 *12Exhibit 10.20 to Fixed ChargesForm 10-K filed February 27, 2019 10.23 Exhibit 10.26 to Form 10-K filed February 27, 2020 *21Exhibit A to definitive proxy statement filed March 26, 2021 10.25 Exhibit 10.27 to Form 10-Q filed August 5, 2021 10.26 Exhibit 10.6 to Form 10-K filed February 26, 2016 58PART IV10.27 Exhibit 10.4 to Form 8-K filed September 5, 2013 10.28 Exhibit 10.28 to Form 10-K filed February 27, 2023 *10.29 *10.30 *10.31 *10.32 *10.33 *10.34 *21.1 *23.1 *23.1*23.2 *23.4 *31.1 *31.2 *31.2*32.1 *32*99.1 99.1Exhibit 99.1 of Murphy's Form 10-KRyder Scott reserves audit report for the year ended December 31, 2013*99.3 99.2Exhibit 99.2 of Murphy's Form 10-KGaffney, Cline independent audit report for the year ended December 31, 2014101.INS 99.3Form of employee time-based restricted stock unit grant agreementExhibit 99.1 of Murphy’s Form 10-Q report filed November 6, 201399.4Exhibit 99.3 of Murphy’s Form 10-K report for the year ended December 31, 201099.5Exhibit 99.5 of Murphy’s Form 10-K report for the year ended December 31, 200899.6Exhibit 99.2 of Murphy’s Form 10-Q report filed November 6, 201354ExhibitNo.Incorporated by Reference to99.7Exhibit 99.1 of Murphy’s Form 10-Q report filed November 6, 201299.8Exhibit 99.6 of Murphy’s Form 10-K report for the year ended December 31, 2012 and Exhibit 99.3 of Murphy's Form 10-Q report filedMay 7, 201499.9Form of performance-based restricted stock unit-cash grant agreementExhibit 99.7 of Murphy’s Form 10-K report for the year ended December 31, 201299.10Exhibit 99.1 of Murphy's Form 10-Q report filed May 7, 201499.11Form of time-based restricted stock unit-cash grant agreementExhibit 99.2 of Murphy's Form 10-Q report filed May 7, 2014101.INS101.SCH 101.SCH101.CAL 101.CAL101.DEF 101.DEF101.LAB 101.LAB101.PRE 101.PRE104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) 5559SIGNATURESPursuant to the requirements of Section 13 or 15(d) 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.MURPHY OIL CORPORATION2018PresidentPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 23, 20182024 by the following persons on behalf of the registrant and in the capacities indicated.R. MADISON MURPHYR. Madison Murphy,James V. Kelley, DirectorWALENTIN MIROSHRoger W. Jenkins, President andWalentin Mirosh, DirectorChief Executive Officer and Director(Principal Executive Officer)R. Madison Murphy, Director T. JAY COLLINST. Jay Collins,Lawrence R. Dickerson, Director/s/ MICHELLE A. EARLEY /s/ ROBERT N. RYAN, JR. /s/ STEVENMichelle A. COSSE/s/ NEAL E. SCHMALESteven A. Cossé, DirectorNeal E. Schmale, DirectorLAWRENCE R. DICKERSONLawrence R. Dickerson,Elisabeth W. Keller, Director/s/ THOMAS J. MIRELES /s/ PAUL D. VAUGHAN /s/ ELISABETH W. KELLER/s/ JOHN W. ECKARTElisabeth W. Keller, DirectorJohn W. Eckart,Thomas J. Mireles, Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)/s/ JAMES V. KELLEY/s/ CHRISTOPHERPaul D. HULSEJames V. Kelley, DirectorChristopher D. Hulse
Vice President and Controller
(Principal Accounting Officer)5660REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTSThe management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The financial statements were prepared in conformity with U.S. generally accepted accounting principles (GAAP) appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and provides an objective, independent opinion about the Company’s consolidated financial statements. The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders. KPMG LLP’s opinion covering the Company’s consolidated financial statements can be found on page 58.The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTINGManagement is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. GAAP. All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth inInternal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2017.KPMG LLP has performed an audit of the Company’s internal control over financial reporting, and their opinion thereon can be found on page 59.64.5761REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the StockholdersandBoard of Directors and Stockholders of Murphy Oil Corporation:Opinion on the Consolidated Financial StatementsWe have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the “Company”)Company) as of December 31, 20172023 and 2016,2022, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2017,2023, and the related notes and financial statement Scheduleschedule II – Valuation Accounts and Reserves (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2023, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control –Integrated– Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2018,2024 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.Basis for OpinionThese consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.Critical Audit MatterThe critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.Estimated oil and gas reserves used in the depletion of producing oil and gas propertiesAs discussed in Note A to the consolidated financial statements, the Company calculates depletion expense related to producing oil and gas properties using the units-of-production method. Under this method, costs to acquire interests in oil and gas properties and costs for the drilling and completion efforts for exploratory wells that find proved reserves and for development wells are capitalized. Capitalized costs of producing oil and gas properties, along with equipment and facilities that support production, are amortized to expense by the units-of-production method. The Company’s internal petroleum reserve engineers estimate proved oil and gas reserves and the Company engages third-party petroleum reserve specialists to perform an62independent assessment. For the year ended December 31, 2023, the Company recorded depreciation, depletion, and amortization expense of $861.6 million.We identified the assessment of the estimated oil and gas reserves used in the depletion of producing oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of total proved oil and gas reserves, which is an input to the depletion expense calculation. Estimating proved oil and gas reserves requires the expertise of professional petroleum reserve engineers based on their estimates of forecasted production, forecasted operating costs, future development costs, and oil and gas prices.The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion calculation process, including controls related to the estimation of proved oil and gas reserves. We evaluated (1) the professional qualifications of the internal petroleum reserve engineers, third-party petroleum reserve specialists, and external engineering firm, (2) the knowledge, skills, ability of the Company’s internal petroleum reserve engineers and third-party petroleum reserve specialists, and (3) the relationship of the third-party petroleum reserve specialists and external engineering firm to the Company. We analyzed and assessed the calculation of depletion expense for compliance with industry and regulatory standards. We compared the forecasted production assumptions used by the Company to historical production rates. We compared the forecasted operating costs to historical results. We also evaluated the forecasted nature and timing of future development costs by obtaining an understanding of the development projects and comparing the development projects with the available development plans. We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices and recalculated the relevant market differentials. In addition, we read and considered the report of the Company’s third-party petroleum reserve specialists in connection with our evaluation of the Company’s proved oil and gas reserve estimates./s/ KPMG LLPWe have served as the Company’s auditor since 1952.Houston, TexasFebruary 23, 2018peaddressees required20245863REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Stockholdersand theBoard of Directors and Stockholders of Murphy Oil Corporation:Opinion on Internal Control Over Financial ReportingWe have audited Murphy Oil Corporation and subsidiaries’ (the “Company”)Company) internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control –- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control –- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated balance sheets of the Company as of December 31, 20172023 and 2016,2022, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2017,2023, and the related notes and financial statement Scheduleschedule II – Valuation Accounts and Reserves (collectively, the “consolidatedconsolidated financial statements”)statements), and our report dated February 23, 20182024 expressed an unqualified opinion on those consolidated financial statements.Basis for OpinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management –- Internal Control Over Financial reporting.Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control Over Financial ReportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate./s/ KPMG LLPHouston, TexasFebruary 23, 201820245964MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED BALANCE SHEETSDecember 31 (Thousands of dollars except share amounts) December 31 (Thousands of dollars except share amounts) 2023 2022 ASSETS Current assets Current assets 964,988 872,797
the date of acquisition111,542
in 2017 and 2016243,472 357,099 105,127 127,071 Cash and cash equivalents Cash and cash equivalents Accounts receivable, net Inventories 35,087 63,604 22,929 27,070 1,371,603 1,559,183
depletion and amortization of $12,280,741 in 2017 and $12,607,815 in 20168,220,031 8,316,188 Total current assets Total current assets Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $13,135,385 in 2023 and $12,489,970 in 2022 Operating lease assets 211,543 365,935 57,765 54,554 9,860,942 10,295,860 Total assets Total assets LIABILITIES AND EQUITY 9,902 569,817 Current liabilities Current liabilities Current maturities of long-term debt, finance lease Current maturities of long-term debt, finance lease Current maturities of long-term debt, finance lease 595,916 784,975 44,604 13,920 23,574 28,167 Operating lease liabilities 156,681 102,777 3,530 2,776 834,207 1,502,432 2,906,520 2,422,750 159,098 69,081 Total current liabilities Total current liabilities Long-term debt, including finance lease obligation 709,299 681,528 631,627 617,490 85,900 Non-current operating lease liabilities Deferred income taxes Total liabilities Total liabilities Total liabilities Equity
195,055,724 shares in 2017 and 2016195,056 195,056 Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued 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 917,665 916,799 5,245,242 5,729,596 (462,243) (628,212) (1,275,529) (1,296,560) 4,620,191 4,916,679 9,860,942 10,295,860 Murphy Shareholders' Equity Noncontrolling interest Total equity Total liabilities and equity See Notes to Consolidated Financial Statements, page 65.70.6065MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS2,097,695 1,809,575 2,787,116 127,434 1,663 154,155 2,225,129 1,811,238 2,941,271 468,323 559,360 832,306 43,618 43,826 65,794
lease amortization122,834 101,861 470,924 222,766 265,210 306,663 957,719 1,054,081 1,619,824 95,088 2,493,156 15,000 39,100 42,590 46,742 48,665 30,706 13,806 360,635 1,903,556 2,219,074 6,197,967 321,573 (407,836) (3,256,696) (67,988) 62,891 91,809 (181,783) (148,170) (117,375) (249,771) (85,279) (25,566) 71,802 (493,115) (3,282,262) 382,738 (219,172) (1,026,490) (310,936) (273,943) (2,255,772) (853) (2,027) (15,061) (311,789) (275,970) (2,270,833) (1.81) (1.59) (12.94) (0.01) (0.09) (1.81) (1.60) (13.03) (1.81) (1.59) (12.94) (0.01) (0.09) (1.81) (1.60) (13.03) 1.00 1.20 1.40 172,524 172,173 174,351 172,524 172,173 174,351 Years Ended December 31 (Thousands of dollars except per share amounts) 2023 2022 2021 Revenues and other income Revenue from production $ 3,376,639 $ 4,038,451 $ 2,801,215 Sales of purchased natural gas 72,215 181,689 – Total revenue from sales to customers 3,448,854 4,220,140 2,801,215 (Loss) on derivative instruments – (320,410) (525,850) Gain on sale of assets and other income 11,293 32,932 23,916 Total revenues and other income 3,460,147 3,932,662 2,299,281 Costs and expenses Lease operating expenses 784,391 679,342 539,546 Severance and ad valorem taxes 42,787 57,012 41,212 Transportation, gathering and processing 232,985 212,711 187,028 Costs of purchased natural gas 51,682 171,991 – Exploration expenses, including undeveloped lease amortization 234,776 133,197 69,044 Selling and general expenses 117,306 131,121 121,950 Depreciation, depletion and amortization 861,602 776,817 795,105 Accretion of asset retirement obligations 46,059 46,243 46,613 Impairment of assets – – 196,296 Other operating expense 46,530 137,518 21,052 Total costs and expenses 2,418,118 2,345,952 2,017,846 Operating income from continuing operations 1,042,029 1,586,710 281,435 Other income (loss) Other (loss) income (8,587) 14,310 (16,771) Interest expense, net (112,373) (150,759) (221,773) Total other loss (120,960) (136,449) (238,544) Income from continuing operations before income taxes 921,069 1,450,261 42,891 Income tax expense 195,921 309,464 (5,862) Income from continuing operations 725,148 1,140,797 48,753 Loss from discontinued operations, net of income taxes (1,467) (2,078) (1,225) Net income including noncontrolling interest 723,681 1,138,719 47,528 Less: Net income attributable to noncontrolling interest 62,122 173,672 121,192 NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 661,559 $ 965,047 $ (73,664) INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ 4.27 $ 6.23 $ (0.47) Discontinued operations (0.01) (0.01) (0.01) Net income (loss) $ 4.26 $ 6.22 $ (0.48) INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 4.23 $ 6.14 $ (0.47) Discontinued operations (0.01) (0.01) (0.01) Net income (loss) $ 4.22 $ 6.13 $ (0.48) Cash dividends per common share $ 1.100 $ 0.825 $ 0.500 Average common shares outstanding (thousands) Basic 155,234 155,277 154,291 Diluted 156,646 157,475 154,291 See Notes to Consolidated Financial Statements, page 65.1 Reclassified to conform to current presentation (see Note A).6166MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)Years Ended December 31 (Thousands of dollars) Years Ended December 31 (Thousands of dollars) 2023 2022 2021 Net income including noncontrolling interest Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation Net gain (loss) from foreign currency translation Net gain (loss) from foreign currency translation Retirement and postretirement benefit plans Deferred loss on interest rate hedges reclassified to interest expense (311,789) (275,970) (2,270,833) 171,725 66,449 (546,705) (7,682) 7,955 10,492
interest expense.1,926 1,926 1,926 165,969 76,330 (534,287) (145,820) (199,640) (2,805,120) Other comprehensive income (loss) Other comprehensive income (loss) Comprehensive income including noncontrolling interest Less: Comprehensive income attributable to noncontrolling interest COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY See Notes to Consolidated Financial Statements, page 65.70.6267MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(311,789) (275,970) (2,270,833)
continuing operations activities:853 2,027 15,061 957,719 1,054,081 1,619,824 95,088 2,493,156 3,794 7,296 (4,163) 15,047 296,845 61,776 43,417 75,312 42,590 46,742 48,665 260,420 (387,843) (978,030) (127,434) (1,663) (154,155) 136,414 (38,689) 35,064 113,289 44,764 (4,836) 1,129,675 600,795 1,183,369 (1,009,667) (926,948) (2,549,736) 69,506 1,155,144 423,911 (212,661) (695,879) (911,787) 320,828 761,000 1,129,139 (7,230) (13,648) (831,994) 286,087 (1,922,121) 541,597 541,444 600,000 (550,000) (600,000) (450,000) (17,133) (10,447) (10,434) (250,000) (14,085) (172,565) (206,635) (244,998) (7,116) (1,158) (9,129) (205,217) (290,881) (364,561) 10,905 (15,005) 5,314 (12,505) 192,585
of discontinued operations(1,600) 182,894 1,327 (6,387) 10,294 92,191 589,614 (910,125) 872,797 283,183 1,193,308 964,988 872,797 283,183 Years Ended December 31 (Thousands of dollars) 2023 2022 2021 Operating Activities Net income including noncontrolling interest $ 723,681 $ 1,138,719 $ 47,528 Adjustments to reconcile net income to net cash provided by continuing operations activities Depreciation, depletion and amortization 861,602 776,817 795,105 Deferred income tax expense (benefit) 179,823 286,079 (4,146) Unsuccessful exploration well costs and previously suspended exploration costs 169,795 82,085 17,339 Contingent consideration payment (139,574) – – Long-term non-cash compensation 61,953 89,246 63,382 Accretion of asset retirement obligations 46,059 46,243 46,613 Amortization of undeveloped leases 10,925 13,300 18,925 Mark to market loss on contingent consideration 7,113 78,285 63,147 Mark to market (gain) loss on derivative instruments – (214,788) 112,113 Loss from discontinued operations 1,467 2,078 1,225 Gain from sale of assets (12) (17,899) – Impairment of assets – – 196,296 Other operating activities, net (74,716) (34,193) (53,821) Net (increase) decrease in noncash working capital (99,361) (65,728) 118,457 Net cash provided by continuing operations activities 1,748,755 2,180,244 1,422,163 Investing Activities Property additions and dry hole costs 1(1,066,015) (985,461) (650,235) Acquisition of oil and natural gas properties 1(35,578) (128,538) (20,244) Proceeds from sales of property, plant and equipment 102,913 4,528 270,503 Property additions for King's Quay FPS – – (17,734) Net cash required by investing activities (998,680) (1,109,471) (417,710) Financing Activities Borrowings on revolving credit facility 600,000 400,000 165,000 Repayment of revolving credit facility (600,000) (400,000) (365,000) Retirement of debt (498,175) (647,707) (876,358) Early redemption of debt cost – (8,295) (39,335) Repurchase of common stock (150,022) – – Contingent consideration paid (60,243) (81,742) – Cash dividends paid (170,978) (128,219) (77,204) Distributions to noncontrolling interest (29,382) (183,038) (137,517) Withholding tax on stock-based incentive awards (14,276) (17,631) (5,209) Finance lease obligation payments (622) (636) (803) Debt issuance, net of cost – – 541,913 Issue costs of debt facility (20) (14,353) – Net cash required by financing activities (923,718) (1,081,621) (794,513) Net cash required by discontinued operations – (14,500) – Effect of exchange rate changes on cash and cash equivalents (1,246) (3,873) 638 Net (decrease) increase in cash and cash equivalents (174,889) (29,221) 210,578 Cash and cash equivalents at beginning of period 491,963 521,184 310,606 Cash and cash equivalents at end of period $ 317,074 $ 491,963 $ 521,184 1Investments are Canadian government securities with maturities greater than 90 days at Certain prior-period amounts have been reclassified to conform to the date of acquisition.See Notes to Consolidated Financial Statements, page 65.70.6368MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
400,000 shares, none issued
December 31, 2017, 2016 and 2015, issued 195,055,724 shares
at December 31, 2017, 2016 and 2015.195,056 195,056 195,040 16 195,056 195,056 195,056 916,799 910,074 906,741 (12,017) (376) (26,553) (10,078) (38,415) 27,496 29,119 42,322 (77) (299) (198) 917,665 916,799 910,074 5,729,596 6,212,201 8,728,032 (311,789) (275,970) (2,270,833)
and $1.40 per share in 2015(172,565) (206,635) (244,998) 5,245,242 5,729,596 6,212,201 (628,212) (704,542) (170,255) 171,725 66,449 (546,705) (7,682) 7,955 10,492
net of income taxes1,926 1,926 1,926 (462,243) (628,212) (704,542) (1,296,560) (1,306,061) (1,086,124) (250,000) 146 509 491 20,885 8,992 29,572
22,853,547 shares of Common Stock in 2016 and 23,021,013
shares of Common Stock in 2015.(1,275,529) (1,296,560) (1,306,061) 4,620,191 4,916,679 5,306,728 Years Ended December 31 (Thousands of dollars except number of shares) 2023 2022 2021 Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued$ – $ – $ – Common Stock – par $1.00, authorized 450,000,000 shares at December 31, 2023, 2022 and 2021, issued 195,100,628 shares at December 31, 2023, 2022 and 2021Balance at beginning and end of year 195,101 195,101 195,101 Capital in Excess of Par Value Balance at beginning of year 893,578 926,698 941,692 Share-based compensation 29,386 25,242 25,429 Restricted stock transactions and other 1(42,667) (58,362) (40,423) Balance at end of year 880,297 893,578 926,698 Retained Earnings Balance at beginning of year 6,055,498 5,218,670 5,369,538 Net income (loss) for the year attributable to Murphy 661,559 965,047 (73,664) Cash dividends paid (170,978) (128,219) (77,204) Balance at end of year 6,546,079 6,055,498 5,218,670 Accumulated Other Comprehensive Loss Balance at beginning of year (534,686) (527,711) (601,333) Foreign currency translation (losses) gains, net of income taxes 36,598 (106,335) 12,116 Retirement and postretirement benefit plans, net of income taxes (23,029) 99,360 59,816 Deferred loss on interest rate hedge reclassified to interest expense,
net of income taxes– – 1,690 Balance at end of year (521,117) (534,686) (527,711) Treasury Stock Balance at beginning of year (1,614,717) (1,655,447) (1,690,661) Purchase of treasury shares (151,241) – – Awarded restricted stock, net of forfeitures 28,392 40,730 35,214 Balance at end of year – 42,351,986 shares of common stock in 2023, 39,633,309 shares of common stock in 2022 and 40,637,578 shares of common stock in 2021 (1,737,566) (1,614,717) (1,655,447) Murphy Shareholders’ Equity 5,362,794 4,994,774 4,157,311 Noncontrolling Interest Balance at beginning of year 154,119 163,485 179,810 Net income attributable to noncontrolling interest 62,122 173,672 121,192 Distributions to noncontrolling interest owners (29,382) (183,038) (137,517) Balance at end of year 186,859 154,119 163,485 Total Equity $ 5,549,653 $ 5,148,893 $ 4,320,796 1 Prior-period amounts have been aggregated to conform to the current period presentation.See Notes to Consolidated Financial Statements, page 65.70.6469MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThese notes are an integral part of the consolidated financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 60-64 70-102of the Form 10-K report.Note A – Significant Accounting PoliciesNATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States Canada and MalaysiaCanada and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017. In addition, Murphy Oil sold its downstream retail marketing assets in the United Kingdom in 2015. See Notes C and E for more information regarding the sale of these assets.BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of the Company and are presented in conformity with GAAP.The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volume, revenues, costs, assets and liabilities including the 20% noncontrolling interest in MP GOM in accordance with accounting for noncontrolling interest as prescribed by Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-10-45, “Consolidations”. Other investments are generally carried at cost. All significant intercompanyIntercompany accounts and transactions have beenare eliminated.BeginningUSE OF ESTIMATES – Preparing the financial statements of the Company in 2017, certain reclassifications in presentation have been madeaccordance with GAAP requires management to make a number of estimates and assumptions that affect the Consolidated Statementsreporting of Operations. The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statementsamounts of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of totalassets, liabilities, revenues and is now presented below Operating income (loss)expenses and the disclosure of contingent assets and liabilities. Actual results may differ from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and are now presented below “Operating income (loss) from continuing operations.” Previously reported periods have been reclassified to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer.customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties, in which Murphy shares anin the undivided interest with other producers, are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The companyCompany follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 20172023 and 2016,2022, the liabilities for natural gas balancing were immaterial. See Note B for further discussionGains and losses on revenue recognition.CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2016, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $111.5 million. These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.65MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued20172023 and 2016,2022, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas.gas and operating costs related to joint venture partners working interest share. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers, joint venture partners and historical write-off experience. Any trade accounts receivable balances written off are70MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote A – Significant Accounting Policies (Continued)charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations. Unsold crude oil production is carried in inventory at the lower of cost generally applied(applied on a first-in, first-out (FIFO) basis or market, and includes costs incurred to bring the inventory to its existing condition.condition), or market. Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment.PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, the leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant“Property, plant and Equipmentequipment” when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete.Oil and natural gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when there are indications that the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. There waswere no impairment recordedimpairments recognized in 2017. During 20162023 and 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2016, the Company recognized pretax noncash impairments charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairments charges of $2.5 billion to reduce the carrying value of certain producing properties in Malaysia, Western Canada and the Gulf of Mexico to their estimated fair value. See also Note E for further discussion of impairment charges. The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled, or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and natural gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligationARO and the recorded liability is recognized as a gain or loss in the Company’s earnings.Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production. Unit rates are computed for unamortized explorationdevelopment drilling and developmentcompletion costs using proved developed reserves; unit rates for unamortized leasehold costsreserves and asset retirementacquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being66MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSCAPITALIZED INTEREST – Continueddepreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in net loss as a separate component of revenues.Turnarounds for coking units at Syncrude Canada Ltd. were scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varied depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease operating expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. The Company sold its interest in Syncrude during 2016.Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and natural gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property,“Property, plant and equipmentequipment” in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.LEASES – At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842, “Leases”. If a lease is present, further criteria is assessed to determine if the lease should be classified as an71MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote A – Significant Accounting Policies (Continued)operating or finance lease. Operating leases are presented on the Consolidated Balance Sheets as “Operating lease assets” with the corresponding lease liabilities presented in “Operating lease liabilities” and “Non-current operating lease liabilities”. Finance lease assets (related to Brunei) are presented on the Consolidated Balance Sheets within “Property, plant and equipment”, with the corresponding liabilities presented in “Current maturities of long-term debt, finance lease” and “Long-term debt, including finance lease obligation”.Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.Operating leases are expensed according to their nature and recognized in “Lease operating expenses”, “Selling and general expenses” or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with the relevant expenses recognized in “Depreciation, depletion and amortization” and “Interest expense, net” on the Consolidated Statement of Operations.ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists, and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized.INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax basesbasis of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period.Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested. On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note I) and a provision for this impact has been recorded. Also, deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested. Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% likely of being realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings.earnings as part of interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated“Accumulated Other Comprehensive LossLoss” in Consolidated Statements of Stockholders’ Equity.72MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote A – Significant Accounting Policies (Continued)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. Sale and purchase contracts in the normal course of business are not designated as hedges for accounting purposes. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to67MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedAccumulated“Accumulated other comprehensive lossloss” in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in Accumulated“Accumulated other comprehensive lossloss” is recognized immediately in earnings.Fair Value Measurements All commodity price derivatives for the periods provided are not designated as cash flow or fair value hedges and therefore changes in fair value are recognized in earnings.FAIR VALUE MEASUREMENTS – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.STOCK-BASED COMPENSATIONEquity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units (PSUs) that are equity settled, and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock unitsPSUs that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense, when known.Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR),(SARs) and cash-settled restricted time-based stock units (CRSU) and phantom stock units(CRSUs) as liability awards. Expense associated with these awards areis recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU,SARs and the period-end price of the Company’s common stock for time-based CRSU and phantom units.CRSUs. When SARSARs are exercised and when CRSU and phantom unitsCRSUs settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards.73MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote A – Significant Accounting Policies (Continued)PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated“Accumulated other comprehensive loss.loss”. The remaining amounts in Accumulated“Accumulated other comprehensive lossloss” include net actuarial losses and prior service (cost) credit.NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs, as the inclusion would have the effect of reducing the diluted loss per share.USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.68MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedAccounting Principles AdoptedCompensation – Stock Compensation.None affecting the Company.Recent Accounting PronouncementsIncome Tax Disclosures. In March 2016,December 2023 the Financial Accounting Standards Board (FASB)FASB issued an Accounting Standards Update (ASU) intended 2023-09 Income Taxes (Topic 740): Improvements 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.Income Tax Disclosures. The amendments in this ASU werestandard becomes effective for annual periods beginning after December 15, 2016,2024. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. Murphy is currently evaluating the impact of adopting this standard.Reportable Segment Disclosures. In November 2023 the FASB issued ASU 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The standard becomes effective for fiscal years beginning after December 15, 2023, 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.Business Combinations. In January 2017, the FASB issued an 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 periodsfiscal years beginning after December 15, 2017,2024. The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods within those periods. The prospective approachstandard does not affect our determination of significant segments. Murphy is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adoptedcurrently evaluating the impact of adopting this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.Recent Accounting PronouncementsNote C – Revenue from Contracts with Customers. In May 2014,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 FASB issued an ASU to establish a comprehensive newglobe. The Company’s revenue recognition standard for contracts with customers that will supersede most currentfrom sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, 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 servicesfrom sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids and natural gas.For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an amount that reflectsagent for the consideration the entity expects to be entitled to in exchangeworking interest owner and recognizes revenue only for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Company has performed a review of contracts in each of its revenue streams and has developed accounting policies to address the provisionsown share of the ASU. As a resultcommingled production. The exception to this is the reporting of this review, the Company’s gross revenuesnoncontrolling interest in MP GOM as prescribed by GAAP.U.S. - In the United States, the Company primarily produces oil and expenses may be impactednatural 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 is transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the determination of whether it is acting as a principal or an agent in certain transactions. The Company adopted the new standard on January 1, 2018, using the modified retrospective method and does not currently expect net earnings, revenues or expenses to be materially impacted. The Company continues to evaluate the impact of this and other provisions of the ASU on related disclosures. Leases. In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilitiesvolumes on the balance sheetbill of lading and disclosing key information about leasing arrangements. The main difference between previous GAAP and this ASU is the recognitionpoint of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in the first quartercustody transfer.7469NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedCompensation – Retirement Benefits. In 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. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolidated financial statements and related footnote disclosures.Compensation – Stock Compensation. 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. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolidated financial statements and related footnote disclosures.Note C – Discontinued Operations and Assets Held for SaleDisaggregation of RevenueThe Company has accountedreviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.The Company’s revenues and other income for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.The following table presents the carrying valueeach of the major categories of assets and liabilities of U.K. discontinued refining and marketing operations and Seal operationsthree year presented were as follows.Years Ended December 31, (Thousands of dollars) 2023 2022 2021 Net crude oil and condensate revenue United States Onshore $ 676,139 $ 856,219 $ 626,136 Offshore 12,072,353 2,229,658 1,478,993 Canada Onshore 78,088 131,400 119,799 Offshore 78,650 117,747 92,741 Other 11,022 22,824 4,924 Total crude oil and condensate revenue 2,916,252 3,357,848 2,322,593 Net natural gas liquids revenue United States Onshore 33,178 64,015 50,189 Offshore 147,434 60,424 44,411 Canada Onshore 8,914 18,338 16,375 Total natural gas liquids revenue 89,526 142,777 110,975 Net natural gas revenue United States Onshore 21,346 64,037 39,803 Offshore 171,332 161,160 81,944 Canada Onshore 278,183 312,629 245,900 Total natural gas revenue 370,861 537,826 367,647 Revenue from production 3,376,639 4,038,451 2,801,215 Sales of purchased natural gas United States Offshore – 204 – Canada Onshore 72,215 181,485 – Total sales of purchased natural gas 72,215 181,689 – Total revenue from sales to customers 3,448,854 4,220,140 2,801,215 (Loss) gain on crude contracts – (320,410) (525,850) Gain on sale of assets and other income11,293 32,932 23,916 Total revenue and other income $ 3,460,147 $ 3,932,662 $ 2,299,281 1 Includes revenue attributable to noncontrolling interest in Canada reflected as held for saleMP GOM.In 2022, the Company included additional line items on the Company’sface of the Consolidated Balance Sheets at December 31, 2017Statements of Operations to report “Sales of purchased natural gas” and 2016.16,631 4,126 6,298 22,944 22,929 27,070 837 270 2,693 2,506 3,530 2,776 85,900 The asset retirement obligation at December 31, 2016 relates to well“Costs of purchased natural gas”. Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and facility abandonmenthas risks and rewards of ownership. Sales of natural gas are reported when the contractual performance obligations are satisfied. This occurs at the Seal field in Canada which were assumed bytime the purchasing company uponproduct is delivered to a third party purchaser at the completioncontractually determinable price.7570NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedContract Balances and Asset RecognitionAs of December 31, 2023 and 2022, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $193.7 million and $201.1 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.The resultsCompany has not entered into any revenue contracts that have financing components as of operationsDecember 31, 2023, 2022 or 2021.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 discontinued operations are presentedthe 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 December 31, 2023, the Company had the following table.854 1,464 381,747 (853) (2,027) (6,758) (4,990) (853) (2,027) (11,748) 3,313 (853) (2,027) (15,061) Certain reclassifications have been madesales contracts in place which are expected to 2016 and 2015 Revenuesgenerate revenue from sales to align with currentcustomers for a period presentation(see Note A).Note D – InventoriesInventories consistedover 12 months starting at the inception of the following at December 31, 2017contract:Long-Term Contracts Outstanding at December 31, 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 2025 Contracts to sell natural gas at USD index pricing 25 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 pricing 124 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD fixed pricing 25 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD index pricing 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 USD index pricing 30 MMCFD Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCFD Fixed price contracts are accounted for as normal sales and 2016.purchases for accounting purposes.20,153 17,146 84,974 109,925 105,127 127,071 76MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote ED – Property, Plant and Equipment20,329,930 8,120,293 20,767,772 8,214,740 170,842 99,738 156,231 101,448 20,500,772 8,220,031 20,924,003 8,316,188 600,423 198,349 595,138 188,689 2. December 31, 2023 December 31, 2022 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 21,228,490 $ 8,201,475 2 $ 20,567,489 $ 8,204,463 2 Corporate and other 132,092 23,722 150,498 23,553 Property, plant and equipment $ 21,360,582 $ 8,225,197 $ 20,717,987 $ 8,228,016 ¹ Includes unproved mineral rights as follows: $ 351,000 $ 228,329 $ 476,981 $ 344,507 2 Includes $38,670$15,356 in 20172023 and $48,053$18,319 in 20162022 related to administrative assets and support equipment.DivestmentsIn January 2017, a Canadian subsidiary ofOn September 15, 2023, the Company completed its dispositionthe previously announced divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash proceeds of C$139.0 million. No gain or loss was recorded related to this transaction, and the Seal field in Western Canada. Total cash consideration to Murphy upon closingeffective date of the transaction was $48.8March 1, 2023.During the third quarter of 2022, the Company completed the disposition of its 62.5% operated working interest of the Thunder Hawk field for a purchase price of $20.0 million less closing adjustments of $23.1 million, resulting in a total net payment to the buyer of $3.1 million. Additionally, the buyer assumed the asset retirement obligationobligations of approximately $85.9$47.9 million. A $129.0$17.9 million pretax gain on sale was reportedrecorded in 2017the period 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 $19.6 million. There were no gains or losses recorded related to the non-core Eagle Ford Shale sales.2016, a Canadian subsidiary ofSeptember 2022, the Company completed the saledisposition of its five percent, non-operatedthe Block CA-2 asset in Brunei for contingent consideration valued at approximately $8.7 million. No gain or loss was recorded related to this sale.AcquisitionsIn August 2022, the Company acquired an additional working interest of 3.37% in Syncrude Canada Ltd. (Syncrude) asset to Suncor Energy Inc. (Suncor). The Company receivedthe Lucius field for a purchase price of $78.5 million, net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million associated with the Syncrude divestiture.In 2016, a Canadian subsidiary ofJune 2022, the Company completed a divestitureacquired an additional working interest of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields11.0% in the Tupper areaKodiak field for a purchase price of northeastern British Columbia. Total cash consideration received upon$50.0 million, net of closing was $414.1 million. A gain on sale of approximately $187.0 million wasadjustments.71MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continueddeferred and is being recognized over approximately the next 18 years in the Canadian operating segment. The Company amortized approximately $7.1 million and $5.1 million of the deferred gain during 2017 and 2016, respectively. The remaining deferred gain of $181.7 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2017.AcquisitionIn 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of December 31, 2017, $44.8 million of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.ImpairmentsDuring 2016 and 2015, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties. During 2016, the Company recorded pretax noncash impairment charges of $95.1 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. In 2015, the Company recognized pretax noncash impairment charges of $2.49 billion to reduce the carrying value of certain offshore producing and non-producing properties in the Gulf of Mexico, producing offshore properties in Malaysia and for Western Canada onshore heavy oil producing properties. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. The following table reflects the recognized before tax impairments for each of the three years ended December 31, 2017.328,982 (Thousands of dollars) (Thousands of dollars) (Thousands of dollars) 2023 2022 2021 95,088 683,574 1,480,600 Other Foreign Corporate 95,088 2,493,156 $ $ $ ��In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the owners. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field.Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.35% interest in the Kakap field in Block K Malaysia as of December 31, 2017. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest. 72MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedUnder 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 Companycompany is making sufficient progress assessing the reserves and the economic and operating viability of the project.At December 31, 2017, 20162023, 2022 and 2015,2021, the Company had total capitalized drilling costs pending the determination of proved reserves of $175.6$49.1 million, $148.5$171.9 million and $130.5$179.5 million, respectively. The following table reflects the net changes in capitalized exploratory well costs duringfor each of the three-year periodthree years presented.77MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote D – Property, Plant and Equipment (Continued)
Reclassifications to proved properties of $82.2 million, for the year ended December 31, (Thousands of dollars)2023 2022 2021 Beginning balance at January 1 $ 171,860 $ 179,481 $ 181,616 Additions pending the determination of proved reserves 48 33,440 16,725 Reclassifications to proved properties based on the determination of proved reserves (82,185) – – Divestment – (7,915) – Capitalized exploration well costs charged to expense (40,605) (33,146) (18,860) Ending balance at December 31 $ 49,118 $ 171,860 $ 179,481 2017.148,500 130,514 120,455 51,488 17,986 64,578
determination of proved reserves(15,988) (8,360) (54,519) 175,640 148,500 130,514 The capitalized2023, are primarily related to LDV-4X in Vietnam. Capitalized well costs charged to dry hole expense in 2017 includedof $40.6 million are related to the Marakas-01Cholula-1EXP well in Block SK314A, offshore MalaysiaMexico, and Oso #1 (Atwater Valley 138), and Chinook #7 (Walker Ridge 425) exploration wells in which developmentthe Gulf of the well could not be justified due to noncommercial hydrocarbon quantities found.Mexico. The capitalizedpreceding table excludes well costs chargedof $129.2 million incurred and expensed directly to expense in 2015 included onedry hole during the year ended December 31, 2023, related to the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) explorations well in the Gulf of Mexico in which development of the well also could not be justified due to noncommercial hydrocarbon quantities found in the sidetrack and one project in the Gulf of Mexico deemed unlikely to be developed due to low commodity prices.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 hashave been capitalized. The projects are aged based on the last well drilled in the project.2023 2023 2022 2021
Wells
Projects
Wells
Projects
Wells
Projects(Thousands of dollars)Amount No. of
WellsNo. of
ProjectsAmount No. of
WellsNo. of
ProjectsAmount No. of
WellsNo. of
Projects
costs:Aging of capitalized well costs Zero to one year Zero to one year 41,480 3 2 20,481 1 1 66,032 7 6 $ – – – $ 15,527 2 2 2 2 $ $ 13,273 3 3 5,812 1 1 63,527 5 5 43,200 2 2 57,876 3 85,148 7 1 64,492 6 6,606 3 175,640 13 6 148,500 12 6 130,514 13 6 $ $ 49,118 4 $ 171,860 9 8 $ 179,481 14 8 Of the $134.1$49.1 million of exploratory well costs capitalized more than one year at December 31, 2017, $70.42023, $26.5 million is in Brunei, $43.2the U.S., $15.1 million is in Vietnam, and $20.5$4.8 million is in Malaysia.Canada and $2.7 million is in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.73Note E – InventoriesInventories consisted of the following for the respective periods presented:December 31, (Thousands of dollars)2023 2022 Unsold crude oil $ 10,304 $ 6,546 Materials and supplies 44,150 47,967 Inventories $ 54,454 $ 54,513 78MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote F – Financing ArrangementsAt December 31, 2017, and DebtLong-term debt for the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2021. At December 31, 2017, the Company had no outstanding borrowings under the 2016 facility; however, there were $90.7 million of outstanding letters of credit, which reduce the borrowing capacityrespective periods presented consisted of the 2016 facility. Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offeredfollowing:December 31, (Thousands of dollars) 2023 2022 Notes payable 5.75% notes, due August 2025 $ – $ 248,675 5.875% notes, due December 2027 443,249 543,249 6.375% notes, due July 2028 372,226 451,934 7.05% notes, due May 2029 179,708 250,000 5.875% notes, due December 2042 ¹ 339,761 339,761 Total notes payable 1,334,944 1,833,619 Unamortized debt issuance cost and discount on notes payable (10,107) (15,324) Total notes payable, net of unamortized discount 1,324,837 1,818,295 Capitalized lease obligation, due through March 2029 4,238 4,844 Total debt including current maturities 1,329,075 1,823,139 Current maturities (723) (687) Total long-term debt $ 1,328,352 $ 1,822,452 1Coupon rate plus an applicable margin (Eurodollar rate)may fluctuate 25 basis points if rating is periodically downgraded or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin. Had there been anyupgraded by S&P and Moody’s.The amounts borrowed under the 2016 facility at December 31, 2017, the applicable base interest rate would have been 4.875%. At December 31, 2017, the Company was in compliance with all covenants related to the 2016 facility.On November 17, 2017, the Company entered into the third amendment (Amendment No. 3) to the 2016 facility. Among other things, Amendment No. 3 extends the maturity dateof long-term debt repayable over each of the 2016 facility to August 17, 2021,next five years and reduces the facility fee on revolving commitmentsthereafter are as follows: nil in 2024, nil in 2025, nil in 2026, $443.2 million in 2027, $372.2 million in 2028 and the interest margin on revolving loans and increases the total leverage ratio under the financial covenants from < 3.75:1.00 to < 4.00:1.00.In August 2017, the Company sold $550$519.5 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025. thereafter.The Company incurred transaction costs of $8.4 million on the issuance of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment was paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 3.50% notes in September 2017. The 3.50% 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 originally expired in August 2019, which was subsequently extended to 2021. 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 Companyalso has a shelf registration statement on file with the U.S. Securities and Exchange CommissionSEC that permits the offer and sale of debt and/or equity securities through October 2018.In November 2022, the Company entered into a $800 million revolving credit facility, and the previous revolving credit facility has been terminated effective November 2022. The RCF is a senior unsecured guaranteed facility which expires on November 17, 2027. On the date the Company achieves certain credit ratings (Investment Grade Ratings Date), certain covenants will be modified as set forth in the RCF. In addition, prior to Investment Grade Ratings Date, the Company will be required to comply with a maximum consolidated leverage ratio of 3.50x and a minimum consolidated interest coverage ratio of 2.50x. From and after the Investment Grade Ratings Date, the Company will be required to comply with a maximum ratio of consolidated total debt to consolidated total capitalization of 60%. Borrowings under the RCF bear interest at rates based on either the “Alternate Base Rate”, the “Adjusted Term Secured Overnight Financing Rate (SOFR) Rate”, or the “Adjusted Daily Simple SOFR Rate”, respectively, plus the “Applicable Rate”. The “Alternate Base Rate” of interest is the highest of (a) the Prime Rate in effect on such day, (b) the New York Federal Reserve Bank (NYFRB) Rate in effect on such day plus ½ of 1% and (c) the Adjusted Term SOFR Rate for a one month Interest Period as published two U.S. Government Securities Business Days prior to such day (or if such day is not a U.S. Government Securities Business Day, the immediately preceding U.S. Government Securities Business Day) plus 1%. The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10%. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) 0.10%. The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s and S&P, respectively. The Company incurred $14.4 million in transaction costs and its partners are partiesrecorded the amount to a 25-year lease“Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and paymentsRCF. At December 31, 2023, the Company had no outstanding borrowings under the agreement areRCF and $3.8 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF. At December 31, 2023, the interest rate in effect on borrowings under the facility would have been 7.70%. At December 31, 2023, the Company was in compliance with all covenants related to be made overthe RCF.In November 2023, the Company tendered a 15-year period through March 2029. Current maturitiestotal of long-term$249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $250 million in aggregate principal. The cost of debt and long-term debtextinguishment of $1.3 million is included in “Interest expense, net” on the Consolidated Balance Sheet included $9.9 million and $134.0 million, respectively, associated with this lease atStatement of Operations for the year ended December 31, 2017.2023.7479MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote G – Long-termF - Financing Arrangements and Debt (Continued)2017 2016 550,000 500,000 500,000 600,000 600,000 550,000 550,000 550,000 250,000 250,000 350,000 350,000 2,800,000 2,800,000 (27,433) (23,835) 2,772,567 2,776,165 143,855 216,402 2,916,422 2,992,567 (9,902) (569,817) 2,906,520 2,422,750 1 DueThere were no additional cash costs related to a series of ratings changes by credit agencies, the paying interest ratesNovember 2023 debt extinguishment on the 2027 Notes, 2028 Notes and 2029 Notes for the year ended December 31, 2023.In September 2023, the Company redeemed the remaining $248.7 million principal outstanding of its 2025 Notes. The non-cash costs of debt extinguishment of $0.9 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023.In November 2022, the Company redeemed $200.0 million aggregate principal amount of its 2025 Notes. The cost of debt extinguishment of $3.9 is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022. The cash costs of $2.9 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.In September and October 2022, the Company paid a total of $7.2 million to complete the open market repurchases of $9.2 million aggregate principal amount of its 6.125% senior notes due 2042 (2042 Notes). There were no additional cash costs related to the September and October 2022 debt extinguishment on the 2042 Notes for the year ended December 31, 2022.In August 2022, the Company redeemed the remaining $42.4 million of its 6.875% senior notes due in 2024 (2024 Notes) and December 2042 decreased from 4.7% to 4.45%tendered $100.0 million and 6.125% to 5.875%, respectively, at December 2017.The$98.1 million aggregate principal amount of debt repayable over eachits 2025 Notes and 2028 Notes, respectively. The total cost of the next five yearsdebt extinguishment of $4.0 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022. The debt extinguishment on the 2025 and thereafter2028 Notes had cash costs of $2.0 million and is shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.In June 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% 2024 Notes. The cost of the debt extinguishment of $4.3 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022. The cash costs of $3.4 million are shown as follows: $9.9 million in 2018, $10.4 million in 2019, $11.0 million in 2020, $11.5 million in 2021, $1.11 billion in 2022 and $1.77 billion thereafter.a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.75MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedHG – Asset Retirement ObligationsThe asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2017 and 2016 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 asset retirement obligationARO for 2017 and 2016the respective periods presented is shown in the following table.(Thousands of dollars) (Thousands of dollars) 2023 2022 Balance at beginning of year Accretion Liabilities incurred Revisions of previous estimates Revisions of previous estimates Revisions of previous estimates Liabilities settled 781,057 825,312 42,590 46,742 52,331 13,690 (47,612) (4,511) (29,111) (20,589) (87,456) (91,883) Changes due to translation of foreign currencies Changes due to translation of foreign currencies 10,340 12,296 722,139 781,057 (85,900) (12,840) (13,629) 709,299 681,528 Current portion of liability ¹ Noncurrent portion of liability 1Liabilities held for sale related to Seal properties in Canada which were sold in January 2017.2Other“Other accrued liabilitiesliabilities” on the Consolidated Balance Sheet.The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.In 2017, revisions8076NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote IH – Income TaxesThe components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.(Thousands of dollars)2023 2022 2021 (299,349) (595,196) (1,259,268) United States United States 371,151 102,081 (2,022,994) 71,802 (493,115) (3,282,262) (9,435) U.S. Federal – Current U.S. Federal – Current U.S. Federal – Current 156,065 (197,450) (241,127) 156,065 (197,450) (250,562) Total U.S. Federal 4,230 13,984 (5,294) 122,318 146,861 (40,550) 100,125 (182,567) (730,084) 222,443 (35,706) (770,634) 382,738 (219,172) (1,026,490) The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.25,131 (172,590) (1,148,792) 118,004
earnings (U.S. tax reform)156,000
invested65,000
the U.S. statutory rate12,658 8,582 49,739 2,438 9,090 (3,441) (32,926) (21,336) (16,939) 188,461 (89,473) 2,080 (122,559)
to other foreign exploration expenditures18,601 25,734 40,788 17,832 18,741 (13,747) 382,738 (219,172) (1,026,490) The Tax Cuts and Jobs ActOn December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, the Company recorded a tax expense of $274.0 million directly related to the impactsfor each of the 2017 Tax Act. The charge includes the impactthree years presented.(Thousands of dollars)2023 2022 2021 Income tax expense (benefit) based on the U.S. statutory tax rate $ 193,424 $ 304,555 $ 9,007 Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 7,597 10,823 13,270 State income taxes, net of federal benefit 4,725 7,118 2,500 U.S. tax benefit on certain foreign upstream investments – – (8,916) Change in deferred tax asset valuation allowance related to other foreign exploration expenditures 10,853 24,748 4,814 Tax effect on income attributable to noncontrolling interest (13,046) (36,471) (25,450) Other, net (7,632) (1,309) (1,087) Total $ 195,921 $ 309,464 $ (5,862) 8177NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedcapital expenditures, the migration from a worldwide system of taxation to a territorial system, and the use of new anti-base erosion provisions. The tax expense recorded in 2017 is a reasonable estimate based on published guidance available at this time and is considered provisional. The ultimate impact of the 2017 Tax Act may differ from these estimates due to changes in interpretations and assumptions made by the company, as well as additional regulatory guidance that may be issued. The Company’s statutory U.S. federal income tax rate will be 21% beginning in 2018, a decrease from the previous rate of 35%.As part of the transition of the U.S. tax system to a territorial system, the 2017 Tax Act provides that certain past accumulated undistributed foreign earnings are deemed repatriated. The territorial system is effective January 1, 2018. For financial statement reporting purposes, the Company believes the 2016 tax net operating loss can be carried forward into 2018 and later years to offset U.S. taxable income. The legislation is inconclusive regarding whether the estimated 2017 tax operating loss incurred by the Company prior to the 2017 Tax Act’s required deemed repatriation at December 31, 2017 may be excluded from the deemed repatriation tax computation (Internal Revenue Code Section 965(n)). Based on interpretation and guidance at this time and uncertainty regarding whether the new Section 965(n) election applies to a 2017 loss, the Company’s tax provision reflects the estimated 2017 tax operating loss being applied fully against the deemed income inclusion. This results in the inability to carryforward the 2017 tax operating loss and the creation of unused foreign tax credit carryforwards with a limited ten-year life. A full valuation allowance has been provided against these unused foreign tax credits to be carried forward. If the Company had prepared the 2017 tax provision preserving the 2017 tax loss as a carryforward, the unused foreign tax credits would have been available to offset a large portion of the tax resulting from the deemed inclusion of foreign earnings, and the U.S. deferred tax charge would have been reduced by approximately $120.0 million with the $36 million residual balance reclassified from deferred tax to a deemed repatriation tax payable over eight years. In the event the Internal Revenue Service or other guidance subsequently determines that the 2017 tax operating loss can be preserved as a carryforward to subsequent years with a twenty-year life, the Company will adjust its financial statements in future periods.Note H – Income Taxes (Continued)An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2017 and 2016for the respective periods presented showing the tax effects of significant temporary differences follows.(Thousands of dollars)2023 2022 488,584 572,481 Property and leasehold costs Property and leasehold costs 98,444 170,946 134,444 214,288 29,710 29,710 228,159 33,295 272,930 454,231 U. S. net operating loss U. S. net operating loss Investment in partnership 13,892 16,541 1,266,163 1,491,492 (476,256) (305,389) 789,907 1,186,103 (65,000) Deferred tax on undistributed foreign earnings Deferred tax on undistributed foreign earnings (669,638) (867,343) Other deferred tax liabilities Other deferred tax liabilities (2,824) (21,908) (737,462) (889,251) 52,445 296,852 Net deferred tax (liabilities) assets In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for78MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedand foreign tax credit carryforwards;that in the judgment of management at the present time these tax assets are more likely than not unexpected to be realized. The foreign tax credit carryforwards expire in 2018 through 2027.unrealized. The valuation allowance increased $170.9$10.9 million in 2017 primarily due2023, related all to foreign tax credit carryforwards realized from the deemed repatriation of accumulated undistributed foreign earnings under the 2017 Tax Act.non-U.S. items. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.The Company has an estimateda U.S. net operating loss carryforward of $1.29$1.7 billion at year-end 20172023 with a corresponding deferred tax asset of $272.9$357.5 million. The Company believes the U.S. net operating loss being carried forward will more likely than not be utilized in future periods prior to expirationexpirations in 2036.Under present law, if2036 and 2037.Other InformationCurrently, the Company repatriates earnings from Canada to the United States in the future, it would incur a 5% withholding tax on the amounts repatriated. A provision of $65.0considers $100 million is recorded in the Company’s financial statements for future repatriation of $1.3 billion of Canada’s past foreign earnings no longer deemed indefinitelynot permanently reinvested, with an accompanying $5 million liability. At December 31, 2023, $1.5 billion of past foreign earnings are considered permanently reinvested.Other Informationcurrently expects in 2018closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to repatriate cash toour business and the U.S. of $700 million of Canada’s past earnings not indefinitely invested, which will lead to a tax withholding payment of $35.0 million (provided for as partfuture operation of the $65.0 million for future repatriation). In December 2015, one of the Company’s foreign subsidiaries declared a $2.0 billion dividend payable to its parent. The dividend represented substantially all of the foreign subsidiary’s accumulated retained earnings under U.S. GAAP. The foreign subsidiary’s dividend was settled with an $800 million cash payment plus issuance of a $1.2 billion note payable to its U.S. parent that was settled in June 2016. The dividend was completed without a U.S. current tax impact due to the utilization of the 2015 U.S. tax net operating loss combined with the shareholder’s ability to use foreign tax credits that attached to the dividend. Based on the usage of the 2015 U.S. tax net operating loss, a noncash tax expense of $188.5 million was recorded in 2015, primarily associated with using a U.S. deferred tax asset that without the dividend would otherwise have carried forward to future years.Uncertain Income Tax PositionsThe FASB’s rules for accounting for income tax uncertainties clarify the criteria for recognizing uncertain income tax benefits and require additional disclosures about uncertain tax positions. Under current rules the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon examination.ultimate settlement. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in Deferred“Other taxes payable” and “Deferred credits and other liabilitiesliabilities” in the Consolidated Balance Sheets.Sheets for current and long-term portions, respectively. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.7,417 6,631 6,011 769 756 821 (4,834) 85 30 (201) 3,437 7,417 6,631 82MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote H – Income Taxes (Continued)(Thousands of dollars)2023 2022 2021 Balance at January 1 $ 3,928 $ 2,903 $ 2,832 Additions for tax positions related to current year – 77 71 Additions for tax positions related to prior year 2,456 948 – Balance at December 31 $ 6,384 $ 3,928 $ 2,903 All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded liabilities of $0.3 million as of December 31, 2017, 20162023, 2022 and 20152021, respectively, for interest and penalties of $0.1 million, $0.3 million and $0.2 million, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2017, 2016 and 2015 included net benefits forThere were no interest andor penalties of $0.2 million, $0.1 million and $0.1 million, respectively, associated with uncertain tax positions.positions included in income tax expense for any period presented.79MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedDuring the next twelve months,In 2024, the Company currently expectsdoes not expect to add between $1.0 million and $2.0 million to the liabilityprovision for uncertain taxes for 2018 events.tax positions. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations closing, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2018.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 could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of December 31, 2017,2023, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2014;2016; Canada – 2012;2016; and Malaysia – 2011;2017. The Company has retained certain possible liabilities andUnited Kingdom – 2016.Note JI – Incentive PlansMurphy utilizes cash-based and/or share-based incentive plansawards to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations, using a grant date fair value-based measurement method, over the periods that the awards vest. For share-basedcash-settled equity awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.At December 31, 2017, theThe Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2012 Long-Term Incentive Plan (2012 Long-Term Plan), the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) and the 2012 Annual2020 Long-Term Incentive Plan (2012 Annual(2020 Long-Term Plan). The 2012 Annual PlanAIP 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 Plan authorizes the Committee to make grants of the Company’s Common Stockcommon stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR),SARs, restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents and other stock-based incentives. The 20122020 Long-Term Plan expires in 2022.2030. A total of 8.75 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 this Plan may be grantedshares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in future years.the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan. Based on awards made to date, approximately 2.62.1 million shares remainedare available for grant under the 20122020 Long-Term Plan at December 31, 2017. 2023.The Company also has a 2013 Stock Plan for Non-Employee Directors (Director(2021 NED 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.83MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote I – Incentive Plans (Continued)Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan).The Company generally expects to issue treasury shares to satisfy vesting of restricted stock and restricted stock units.Amounts recognized in the financial statements with respect to share-based plans for each of the three years presented are shown in the following table:table.(Thousands of dollars)2023 2022 2021 40,365 46,300 44,021 Compensation charged against income before income tax benefit 5,017 15,244 13,583 As of December 31, 2017,2023, there were $29.8$47.4 million in compensation costs, to be expensed over approximately the next twothree years, related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable statutory withholding taxes,obligations, upon each stock option exercise and restricted stock award. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the year ended December 31, 2015. There were no income tax benefits realized in either 2017 or 2016 due to no stock option exercises during those years.Share-Settledunit vest. Equity-Settled AwardsSTOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan and the 2007 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is80MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedgenerally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.Changes in stock options outstanding during the last three years are presented in the following table.
Shares
Exercise
Price 5,602,250 57.95 991,000 49.67 (32,349) 40.80 (1,117,613) 31.99 5,443,288 52.93 862,000 17.57 (547,853) 44.23 5,757,435 48.46 603,000 28.51 (1,459,166) 49.34 4,901,269 45.74 3,030,105 53.10 3,542,352 52.26 3,830,535 53.80 3,197,269 54.22 81MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedAdditional information about stock options outstanding at December 31, 2017 is shown below.
Prices per Option
Options
Remaining
in Years
Intrinsic
Value
Options
Remaining
in Years
Intrinsic
Value1,320,000 11,652,680 823,350 439,350 2,757,919 2,757,919 4,901,269 11,652,680 3,197,269 The total intrinsic value of options exercised during 2015 was $0.2 million. There were no options exercised in both 2017 and 2016 as all awards either had no intrinsic value or were not vested. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.Performance-based restricted stock units (PRSUS)PSUs to be settled in Commoncommon shares were granted in each of the last three years2020 under the 20122018 Long-Term Plan, and in 2021, 2022 and 2023 under the 2020 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PRSUSPSUs will not vest, but the recognized compensation cost associated with the stock award would not be reversed. For past awards,PSUs, the performance conditions wereare based on the Company’s total shareholder return over the performance period(80% weighting), compared to an industry peer group of companies.companies, and the EBITDA divided by Average Capital Employed metric (20% weighting) for PSU awards, over the performance period. During the performance period, PRSUSPSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid ornor do voting rights exist on awards of PRSUSPSUs prior to their settlement.Changes in PRSUSPSUs outstanding for each of the last three years are presented in the following table.(Number of stock units)(Number of stock units)2023 2022 2021 992,573 1,103,986 1,397,040 560,000 394,000 455,000 (272,725) (361,096) (521,800) Vested and issued (91,927) (144,317) (226,254) 1,187,921 992,573 1,103,986 82MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued2017, 20162023, 2022 and 20152021 are presented in the following table.2023 2023 2022 2021 Fair value per share at grant date $60.46 $37.77 - $47.37 $16.03 Expected volatility Expected volatility 81.00% 79.00% - 81.00% 74.00% Risk-free interest rate 3.90% 1.39% -2.85% 0.18% Stock beta 1.034 1.195 - 1.200 1.169 Expected life 3.0 years 3.0 years 3.0 years TIME-LAPSE84MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote I – Incentive Plans (Continued)TIME-BASED RESTRICTED STOCK UNITS – Time-lapsed restricted stock units (TRSUS)Time-based RSUs have been granted to the Company’s Non-Employee Directors (NED) under the Directors2018 NED Plan and 2021 NED Plan, and to certain employees under the 20122020 Long-Term Plan. These awardsThe fair value of the time-based restricted stock units awarded for each of the last three years are presented in the following table.Type of Plan Valuation Methodology 2023 2022 2021 Non-Employee Directors 1Closing Stock Price at Grant Date $43.27 $32.84 $13.14 - $23.58 Long-Term Incentive Plan 2Average Low/High Stock Price at Grant Date $42.20 $29.80 - $49.86 $12.30 1 Under the 2021 NED Plan, RSUs granted in 2023 are scheduled to vest in February 2024.2 The RSUs granted under the 2018 and 2020 Long-Term Plan generally vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $28.51 per share in 2017, $17.57 per share in 2016, and $49.67 per share in 2015.Changes in TRSUSRSUs outstanding for each of the last three years are presented in the following table.(Number of share units)2023 2022 2021 923,282 477,244 321,789 419,720 503,555 282,065 (217,633) (32,092) (69,610) (89,389) (25,425) (57,000) 1,035,980 923,282 477,244 EMPLOYEE STOCK PURCHASE PLAN (ESPP)OPTIONS – In 2017, the Company ceased the inclusion of stock options and SARs as a part of the long-term incentive compensation mix. Prior to 2017, the Committee fixed the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixed the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.The Company had an ESPP under whichfair value of each option award was estimated on the Company’s Common stock could have been purchased by eligible U.S. and Canadian employees. Each quarter, an eligible employee could have elected to withhold up to 10%date of his or her salary to purchase sharesgrant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock atand implied volatility on publicly traded at-the-money options on the endCompany’s stock. The Company estimates the expected term of the quarter at a price equal to 90%options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the fair value of the stock as of the first day of the quarter. The ESPP terminated June 30, 2017. Employee stock purchases under the ESPP were 2,564 shares at an average price of $26.85 per share in 2017, 8,962 shares at an average price of $23.41 per share in 2016, and 8,387 shares at an average price of $34.93 per share in 2015. Compensation costs related to the ESPP were estimatedoption is based on the valueU.S. Treasury yield curve in effect at the time of the 10% discount and the fair valuegrant.8583NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote I – Incentive Plans (Continued)Changes in stock options outstanding during the last three years are presented in the following table.Number of
SharesAverage
Exercise
PriceOutstanding at December 31, 2020 2,048,400 40.14 Exercised (170,000) 17.57 Forfeited (558,900) 52.61 Outstanding at December 31, 2021 1,319,500 37.77 Exercised (760,500) 23.29 Forfeited (546,000) 49.65 Outstanding at December 31, 2022 13,000 28.51 Exercised (11,000) 28.51 Forfeited (2,000) 28.51 Outstanding at December 31, 2023 – – Exercisable at December 31, 2020 2,048,400 37.88 Exercisable at December 31, 2021 1,319,500 34.25 Exercisable at December 31, 2022 13,000 28.51 Exercisable at December 31, 2023 – – The total intrinsic value of options exercised during 2023 was $0.16 million. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.Cash-Settled AwardsThe Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SAR), Performance-based restricted stock units (PRSUC), Time-based restricted stock units (TRSUC)SARs and Phantom units.SAR awards have terms similar to stock options. PRSUC terms are similar to other performance-based restricted stock awards. TRSUC areCRSUs generally settledsettle on the third anniversary of the date of grant. Phantom units generally settle three to five years from date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Commoncommon shares. Total pre-tax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $12.9$29.4 million in 2017, $17.22023, $49.3 million in 20162022 and $1.6$18.2 million in 2015.The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $30.5$30.9 million, $25.8$42.9 million and $26.4$29.0 million was recorded in 2017, 20162023, 2022 and 2015,2021, respectively, for these plans.Note KJ – Employee and Retiree Benefit PlansPENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.86MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheetConsolidated Balance Sheets and to recognize changes in that funded status between periods through accumulated“Accumulated other comprehensive loss.loss”.84MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedand fair value of assets and funded status for the years ended December 31, 2017 and 2016 and a statement of the funded status as of December 31, 2017 and 2016.
Benefits
Postretirement
BenefitsPension
BenefitsPension
BenefitsOther
Postretirement
Benefits(Thousands of dollars)2023 2022 2023 2022 Obligation at January 1 Obligation at January 1 815,593 794,589 106,679 115,222 8,279 8,136 1,601 1,864 27,047 25,185 3,444 3,800 2,075 1,278 60,855 58,236 (3,077) (10,627) 318 510 18,751 (30,447) 46 20 (39,910) (40,928) (4,810) (5,369) 822 (19) (8,683) Plan amendments 1Plan amendments 1Plan amendments 1881,932 815,593 106,276 106,679 Fair value of plan assets at January 1 Fair value of plan assets at January 1 519,357 521,682 50,079 61,860 24,918 8,186 2,417 3,581 2,075 1,278 318 510 18,064 (30,609) (39,910) (40,928) (4,810) (5,369) (8,683) (834) Fair value of plan assets at December 31 Fair value of plan assets at December 31 563,825 519,357
Consolidated Balance Sheets at December 315,905 7,591 Deferred charges and other assets Deferred charges and other assets (8,856) (8,184) (5,392) (5,267) (315,156) (295,643) (100,884) (101,412)
at December 31(318,107) (296,236) (106,276) (106,679) Fund Status and net plan liability recognized at December 31 85MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued2017,2023, the Company recognized an increase to its domestic plan benefit obligation related to a plan amendment. The amendment provides a permanent increase to benefits for retirees and beneficiaries who commenced payments prior to 2020.In 2023, the increase to the pension benefits obligation is primarily due to the decrease in the interest rate assumption.At December 31, 2023, amounts included in Accumulated“Accumulated other comprehensive lossloss” (AOCL) in the Consolidated BalanceSheets, before reduction for associated deferred income taxes, which have not been87MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)recognized in net periodic benefit expense are shown in the following table.(Thousands of dollars)Pension
BenefitsOther
Postretirement
BenefitsNet actuarial gain (loss) $ (202,868) $ 44,165 Prior service (credit) cost (20,561) 3,937 $ (223,429) $ 48,102
Benefits
Postretirement
Benefits(269,063) 221 (5,824) 38 (274,887) 259 Amounts included in AOCL at December 31, 2017 that are expected to be amortized into net periodic benefit expense during 2018 are shown in the following table.
Benefits
Postretirement
Benefits(15,890) (1,021) 38 (16,911) 38
Benefit Obligations
Benefit Obligations
of Plan AssetsProjected
Benefit ObligationsProjected
Benefit ObligationsAccumulated
Benefit ObligationsFair Value
of Plan Assets(Thousands of dollars)2023 2022 2023 2022 2023 2022
accumulated benefit obligation
exceeds fair value of plan assets691,923 643,174 640,230 599,730 540,161 497,894
plans where accumulated benefit
obligation exceeds fair value of
plan assets172,364 156,088 163,319 150,780 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 106,276 106,678 106,276 106,678 86MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedended December 31, 2017.
Postretirement BenefitsPension Benefits Pension Benefits Other
Postretirement Benefits(Thousands of dollars)2023 2022 2021 2023 2022 2021 8,279 8,136 17,948 1,601 1,864 3,180 27,047 25,185 33,168 3,444 3,800 4,883 (28,941) (28,154) (34,016)
cost (credit)1,026 1,204 1,560 (74) (75) (82)
(asset) liability(1) 16,691 16,165 15,147 5 992 24,102 22,536 33,806 4,971 5,594 8,973 8,606 Recognized actuarial (gain) loss Recognized actuarial (gain) loss Recognized actuarial (gain) loss Net periodic benefit expense 822 306 (19) 24,102 23,358 42,718 4,971 5,575 8,973 Curtailment expense Curtailment expense Total net periodic benefit expense Termination and curtailment expenses in 2016 and 2015 were primarily related to plan amendments made upon early retirement of certain employees during 2016 and 2015.The preceding tables in this note include the following amounts related to foreign benefit plans.
Benefits
Postretirement
BenefitsPension
BenefitsPension
BenefitsOther
Postretirement
Benefits(Thousands of dollars)2023 2022 2023 2022 222,483 206,502 791 615 212,535 197,575 9,948 8,927 791 615 194 (2,244) 133 154 The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 20172023 and 20162022 and net periodic benefit expense for 20172023 and 2016.2022.
Benefits
Postretirement
Benefits
Benefits
Postretirement
Benefits3.42% 3.94% 3.73% 4.41% 3.66% 3.84% 4.33% 4.24% 5.64% 5.62% 5.64% 5.62% 3.52% 3.52% 3.52% 3.52% 8887MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)Benefit Obligations Net Periodic Benefit Expense Pension
BenefitsOther
Postretirement
BenefitsPension
BenefitsOther
Postretirement
BenefitsDecember 31, December 31, Year Year 2023 2022 2023 2022 2023 2022 2023 2022 Discount rate on obligation, interest cost and service cost 5.03 % 5.30 % 5.15 % 5.41 % 5.27 % 3.13 % 5.41 % 2.86 % Rate of compensation increase 3.52 % 3.50 % – – 3.52 % 3.00 % – – Cash balance interest credit rate 3.20 % 3.20 % – – – – – – Expected return on plan assets – – – – 7.35 % 6.24 % – – The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company, are shown in the following table.(Thousands of dollars)Pension
BenefitsOther
Postretirement
Benefits2024 $ 47,042 $ 4,433 2025 47,424 4,456 2026 48,004 4,479 2027 48,481 4,491 2028 49,834 4,614 2029-2033 248,023 22,037
Benefits
Postretirement
Benefits39,929 6,259 40,236 6,280 41,220 6,357 42,276 6,489 43,554 6,560 227,039 33,971 2017,2023, the future annual rates of increase in the cost of health care were assumed to be 6.7%7.4% for 20172024 decreasing each year to an ultimate rate of 4.5%4.0% in 20382048 and thereafter.Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects.
benefit expense for the year ended December 31, 2017919 (719)
obligation at December 31, 201715,220 (12,277) 2017,2023, the Company made contributions of $18.0$34.7 million to its domestic defined benefit pension plans $6.9and $2.0 million to its domestic postretirement benefits plan. During 2024, the Company currently expects to make contributions of $35.8 million to its domestic defined benefit pension plans, $2.2 million to its foreign defined benefit pension plans and $2.4$4.4 million to its domestic postretirement benefits plan. During 2018, Company currently expects to make contributions of $24.4 million to its domestic defined benefit pension plans, $0.6 million to its foreign defined benefit pension plans and $5.4 million to its domestic postretirement benefits plan.88MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedPlan InvestmentsPLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. The Statement specifies that allOur investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets will be held in a Trust sponsoredvariety of asset classes. Asset classes and target allocations are determined by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee). Members of the Committee are appointed by the Chief Executive Officer of Murphy. The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement. Theour investment goals call for a portfolio of assets consisting of equity,committee and includes equities, fixed income and other investments, including hedge funds, real estate and cash equivalent securities. The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation. The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities. The Company believes that over time a balanced to slightly heavier weighting of the portfolioInvestment managers are prohibited from investing in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans. The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70%; fixed income securities of between 30% and 60%; long/short equity of between 0% and 15%; and cash and equivalents of between 0% and 15%. The Committee is authorized to direct investments within these parameters. Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds. Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term. Generally, no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100 million. Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets. Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity.Company. The fixed income portfolio should not exceed an average maturitymajority of 11 years.plan assets are highly liquid, providing flexibility for benefit payment requirements. The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds. The Committee routinely reviews the investment performance of Investment Managers.For the U.K. retirementcurrent target allocations for plan trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees. The trustees have hired a fiduciary investment manager to manage the assets of the plan within the parameters of the Statement of Investment Principles (Statement). The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Statement while limiting the risk for the funded position of the plan. The Statement specifies a strategy with an allocation goal of 60% Delegated growth fund (DGF) equities and 40% Delegated liability fund (DLF). Also, the allocation goal includes interest rate hedge ratio and inflation rate hedge ratio of 100%. Hewitt Risk Management Services Limited (Manager) has discretion to vary the level of interest rate and inflation hedge ratios from the strategic levels. The DGF is diversified by style, strategy and asset class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies. The DLF aims to provide returns in line with the liabilities of typical pension schemes on an exposure basis in the relevant tenures and instruments (long/short, real/nominal). The DLF holds cash as collateral for the leveraged positions. Small working cash balances are permitted to facilitate daily management of payments and receipts within the plan. The trustee routinely reviews the investment performance of the plan.For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets. A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio. The Policy permits assets to be invested in various Canadian and foreign40-75% equity securities, various20-60% fixed income securities, real estate, natural resource properties or participation rights0-15% alternatives and cash. The objective for plan investments is0-20% cash and equivalents. Asset allocations are rebalanced on a periodic basis throughout the year to achieve a total rate of return equalbring assets to the long-term interest rate assumption used for the going-concern actuarial funding valuation. The normal allocation for 2017 includes total equity securities of 60% with awithin an acceptable range of 55% to 65%target levels.8989NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2017 and 2016the respective balance sheet dates are presentedshown in the following table.December 31, 2023 2022 Equity securities 62.6 % 65.7 % Fixed income securities 29.1 % 23.4 % Alternatives 5.1 % 7.3 % Cash equivalents 3.2 % 3.6 % 100.0 % 100.0 % 60.3 58.4 37.2 39.0 2.5 2.6 100.0 100.0 5.64%7.4% in 20172023 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 5.64%7.4% expected return was based on ancomprised of the weighted average expected average future equity securities return of 7.15%8.4% and a fixed income securities return of 4.26% and is net of4.7%. An average expected investment expensesexpense of 0.60%.0.8% is included in this calculation. Over the last 10 years, the return on funded retirement plan assets has averaged 6.66%3.0%.At December 31, 2017,2023, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.Fair Value Measurements Using (Thousands of dollars)Fair Value at December 31,
2023Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)Significant
Other
Observable
Inputs
(Level 2)Significant
Unobservable
Inputs
(Level 3)Domestic Plans Equity securities: U.S. core equity $ 105,212 $ 105,212 $ – $ – U.S. small/midcap 64,165 64,165 – – Other alternative strategies 3,831 – – 3,831 International equity 31,820 31,820 – – Emerging market equity 10,525 10,525 – – Fixed income securities: U.S. fixed income 132,608 56,381 76,227 – Cash and equivalents 10,412 10,412 — – Total Domestic Plans 358,573 278,515 76,227 3,831 Foreign Plans Equity securities funds 24,389 – 24,389 – Fixed income securities funds 23,930 – 23,930 – Diversified pooled fund 45,162 – 45,162 – Other 20,623 – – 20,623 Cash and equivalents 5,133 – 5,133 – Total Foreign Plans 119,236 – 98,613 20,623 Total $ 477,809 $ 278,515 $ 174,841 $ 24,454
December 31, 2017
in Active
Markets for
Identical Assets
(Level 1)
Other
Observable
Inputs
(Level 2)
Unobservable
Inputs
(Level 3)67,343 67,343 24,544 24,544
alternative strategies50,522 12,572 37,950
trust fund83,960 83,960
equity fund20,774 20,774 79,890 79,890
trust fund13,122 13,122 5,266 5,266 5,871 5,871 351,292 97,758 215,584 37,950 78,666 78,666 103,314 103,314 23,665 23,665 6,888 6,888 212,533 212,533 563,825 97,758 428,117 37,950 9090MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)At December 31, 2016,2022, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.Fair Value Measurements Using (Thousands of dollars)Fair Value at December 31,
2022Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)Significant
Other
Observable
Inputs
(Level 2)Significant
Unobservable
Inputs
(Level 3)Domestic Plans Equity securities: U.S. core equity $ 96,433 $ 96,433 $ – $ – U.S. small/midcap 64,421 64,421 – – Other alternative strategies 12,106 – – 12,106 International equity 44,672 44,672 – – Emerging market equity 13,541 13,541 – – Fixed income securities: U.S. fixed income 85,190 35,661 49,528 – Cash and equivalents 18,719 18,719 – – Total Domestic Plans 335,082 273,447 49,528 12,106 Foreign Plans Equity securities funds 23,877 – 23,877 – Fixed income securities funds 30,727 – 30,727 – Diversified pooled fund 31,246 – 31,246 – Other 20,628 – – 20,628 Cash and equivalents 9,384 – 9,384 – Total Foreign Plans 115,862 – 95,234 20,628 Total $ 450,944 $ 273,447 $ 144,763 $ 32,734
December 31, 2016
Unobservable
Inputs
(Level 3)61,554 61,554 23,103 23,103
alternative strategies48,113 13,999 34,114
trust fund67,451 67,451
equity fund16,006 16,006 78,473 78,473
trust fund13,486 13,486 5,775 5,775 7,821 7,821 321,782 92,478 195,190 34,114 74,108 74,108 97,075 97,075 21,463 21,463 4,929 4,929 197,575 197,575 519,357 92,478 392,765 34,114 Q.For domestic plans, U.S. core, and small/midcap, international, emerging market equity securities and U.S. treasury securities are valued based on daily marketquoted prices as quoted on national stock exchanges orin active markets. For commercial paper securities, the prices received generally utilize observable inputs in the over-the-counter market. Hedged funds and otherpricing methodologies. Other alternative strategies funds consist of threetwo investments. One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthlyannually based on net asset value and permits withdrawals semi-annuallyannually after a 90-day notice, and the thirdother investment is also valued monthlyquarterly based on net asset values and has a two-yearthree-year lock-up period and a 95-day notice following the lock-up period. International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges. The emerging market commingled equity fund is valued monthly based on net asset value. These commingled equity funds can be withdrawn monthly and have a 10-day notice period. U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values. International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values. The fixed income emerging market mutual fund is valued daily based on net asset value. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. and Canadian securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of CanadianU.K. and foreign equity securities, Canadian fixed income securities and cash.securities.91MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote J – Employee and Retiree Benefit Plans (Continued)The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:(Thousands of dollars)
Alternative Strategies2015$ $33,929 (38,389) 185 Relating to assets sold during the period– (11,731) – 201632,734 34,114 711 3,836 Relating to assets sold during the period (8,991) – Purchases, sales and settlements– 2017$ $37,950 THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6%6.0%. Amounts charged to expense for the Company’s match to these plans were $7.8$8.5 million in 2017, $7.42023, $6.0 million in 20162022 and $7.6$5.4 million in 2015.Note LK – Financial Instruments and Risk ManagementDERIVATIVE INSTRUMENTS – Murphy often uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).Exchange. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL untiland amortized to “Interest expense, net” over time. In 2021, the anticipated transactions occur.Commodity Purchase Price RisksThe Company is subject to commodity price risk related to crude oil it produces and sells. During the last three years,2022, the Company had West Texas Intermediate (WTI) crude oil price 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 December 31, 2017,2023 and December 31, 2022, the Company did not have any outstanding crude oil derivative contracts. At December 31, 2021, the Company had 21,00020,000 barrels per day in NYMEX WTI crude oil swap financial contracts maturing ratably during 2018 at an averagea price per barrel of $54.88. At December 31, 2017, the fair value of these WTI contracts of $39.1 million was included in Accounts payable in the Consolidated Balance Sheet. The impact of marking to market these commodity derivative contracts reduced the income before income taxes by $34.0 million for the year ended December 31, 2017.During 2016, the Company had WTI crude oil price swap financial contracts to hedge a portion of its United States production for 2016$44.88 and 2017. At December 31, 2016, the Company had 22,00025,000 barrels per day in NYMEX WTI crude oil swap financialcollar contracts with an average ceiling price per barrel of $75.20 and an average floor price per barrel of $63.24, both maturing ratably during 2017. At December 31, 2016, the fair value2022.9292NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote K – Financial Instruments and Risk Management (Continued)Foreign Currency Exchange RisksThe Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At December 31, 2016,The Company had no foreign currency exchange short-term derivative instruments were outstanding in Canada for approximately $14.2 million to manage the currency riskas of U.S. dollar accounts receivable balances associated with the sale of Canadian crude oil. At December 31, 20172023 and 2016, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. Also shown is the fair value of open foreign currency derivative contracts at December 31, 2016.(39,093) (48,864) (73) For the years ended December 31, 2017 and 2016, theThe gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.9,567 (63,412) 26,714 9,567 (36,698) 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 2012 to match the payment of interest on these notes through 2022. Duringfor each of the three years ended December 31, 2017, $3.0 million of the deferred loss on the interest rate swaps was charged to Interest expensepresented are shown in the Consolidated Statements of Operations. The remaining loss (net of tax) deferred on these matured contracts at December 31, 2017 was $8.4 million, which is recorded, net of income taxes of $4.5 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheets. The Company expects to charge approximately $3.0 million of this deferred loss to Interest expense in the Consolidated Statements of Operations during 2018.93Gain (Loss) (Thousands of dollars)Year Ended December 31, Type of Derivative Contract Statement of Operations Locations 2023 2022 2021 Commodity swaps (Loss) on derivative instruments $ – $ (160,690) $ (510,596) Commodity collars (Loss) on derivative instruments – (159,721) (15,254) MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedCREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S., and Canada and Malaysia, and cost sharing amounts, of operating and capital costs billed to partners, for oil and natural gas fieldsproperties operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended, securityextended. Security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level.associated with any one customer. Cash balances and cash equivalents are placedheld with several major financial institutions, which limit the Company’s exposure to credit risk.risk for its cash assets. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal, because counterparties to the majority of transactions are major financial institutions.Note M – Stockholders’ EquityCommon stock acquired under prior share buyback programs are carried as Treasury stock in the Consolidated Balance Sheets. There were no share repurchases during 2017 or 2016 and no open share buyback programs as ofDecember 31, 2017.During 2015, the Company repurchased Common Stock under variable term, capped accelerated share repurchase transactions (ASR) as authorized by the Board of Directors. These share repurchases during 2015 were as follows:2015Purchase of Treasury Stock$250,000,000 Shares repurchased5,967,313 Note NL – Earnings perPer ShareNet lossincome (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income per Commoncommon share for each of the three years ended December 31, 2017presented. The following table reconciles the weighted-average shares outstanding used for these computations.(Weighted-average shares)2023 2022 2021 172,524,061 172,173,012 174,351,227 Dilutive stock options and restricted stock units ¹ 172,524,061 172,173,012 174,351,227 1Due to a net loss recognized by the Company for the yearsyear ended December 31, 2017, 2016 and 2015,2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.The following table reflects certain options to purchase shares of common stock that were outstanding during each of the three years ended December 31, 2017,presented but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.2023 2023 2022 2021 4,901,269 5,757,435 5,443,288 $45.74 $48.46 $52.93 94MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedOM – Other Financial InformationGAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $(75.4)$10.8 million loss in 2017, $59.72023, $23.0 million gain in 20162022 and $87.9$1.0 million gain in 2015.93MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote M – Other Financial Information (Continued)Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2017presented as shown in the following table.114,401 119,671 297,625 26,883 (5,171) (15,340) 29,570 149,946 (144,845) 3,924 (51,439) (328,078) (36,887) 16,999 24,943 (69,413) 136,414 (38,689) 35,064 68,076 6,707 118,667
$4,322 in 2016 and $7,290 in 2015147,975 127,798 110,386 8,509 13,690 76,775 99,199 158,885 462,474 (Thousands of dollars)2023 2022 2021 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ 47,151 $ (137,228) $ 8,056 (Increase) decrease in inventories 329 (1,534) 12,809 (Increase) decrease in prepaid expenses (1,293) (3,413) 2,003 Increase (decrease) in accounts payable and accrued liabilities ¹ (140,011) 69,854 95,166 Increase (decrease) in income taxes payable (5,537) 6,593 423 Net (increase) decrease in noncash operating working capital $ (99,361) $ (65,728) $ 118,457 Supplementary disclosures: Cash income taxes paid, net of refunds $ 12,356 $ 24,853 $ 2,138 Interest paid, net of amounts capitalized of $14.5 million in 2023, $16.3 million in 2022 and $16.1 million in 2021 108,912 149,957 165,699 Non-cash investing activities: Asset retirement costs capitalized $ 32,975 $ (21,147) $ 54,439 (Increase) decrease in capital expenditure accrual 17,517 (31,397) 9,788 DEEPWATER RIG CONTRACT EXIT COSTS1 Excludes receivable/payable balances relating to mark-to-market of crude contracts.Note N – At year-end 2015,Accumulated Other Comprehensive LossThe components of AOCL on the Company had two deepwater drilling rigsConsolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the Gulffollowing table.(Thousands of dollars)Foreign
Currency
Translation
Gains (Losses)Retirement and
Postretirement
Benefit Plan
Adjustments Total Balance at December 31, 2021 $ (311,895) $ (215,816) $ (527,711) 2022 components of other comprehensive income (loss): Before reclassifications to income (106,335) 87,362 (18,973) Reclassifications to income – 11,998 ¹ 11,998 Net other comprehensive income (106,335) 99,360 (6,975) Balance at December 31, 2022 (418,230) (116,456) (534,686) 2023 components of other comprehensive income (loss): Before reclassifications to income 36,598 (27,580) 9,018 Reclassifications to income – 4,551 ¹ 4,551 Net other comprehensive income (loss) 36,598 (23,029) 13,569 Balance at December 31, 2023 $ (381,632) $ (139,485) $ (521,117) 1 Reclassifications before taxes of Mexico under contract that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The Company reported a pretax charge to Other expense in 2015 totaling $282.0 million that included both the costs incurred in 2015 when the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016. The contract originally scheduled to expire in November 2016 was terminated by the Company. The Company paid approximately $266.7 million related to these contracts in 2016 and reported a pretax benefit to Other expense in 2017 and 2016 of $6.1$5.6 million and $4.3$15.3 million respectively, for the final settlement of the contracts at less than the recorded costs. These amounts are included in Otherthe computation of net periodic benefit expense in the Consolidated Statements2023 and 2022, respectively. See Note J for additional information. Related income taxes of Operations.$1.1 million and $3.3 million are included in income tax expense in 2023 and 2022, respectively.9594MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote P – Accumulated Other Comprehensive LossThe components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 and the changes during 2017 and 2016 are presented net of taxes in the following table.
Currency
Translation
Gains (Losses)
Postretirement
Benefit Plan
Adjustments
Loss on
Interest
Rate
Derivative
Hedges(513,004) (179,260) (12,278) (704,542) 66,449 (3,763) 62,686 11,718 1,926 13,644 66,449 7,955 1,926 76,330 (446,555) (171,305) (10,352) (628,212) 171,725 (17,269) 154,456 9,587 1,926 11,513 171,725 (7,682) 1,926 165,969 (274,830) (178,987) (8,426) (462,243) 1Reclassifications before taxes of $14,821 and $18,036are included in the computation of net periodic benefit expense in 2017 and 2016, respectively. See Note K for additional information. Related income taxes of $5,234 and $6,318are included in income tax expense in 2017 and 2016, respectively.2Reclassifications before taxes of $2,963 are included in Interest expense in both 2017 and 2016. Related income taxes of $1,037 are included in income tax expense in 2017 and 2016. See Note L for additional information.Note QO – Assets and Liabilities Measured at Fair ValueFair Values – RecurringThe Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet.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.96MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continuedat December 31, 2017 and 2016for the respective periods presented are presentedshown in the following table.
savings plans16,158 16,158 13,904 13,904 39,093 39,093 48,864 48,864
derivative contracts73 73 16,158 39,093 55,251 13,904 48,937 62,841 December 31, 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 $ 17,785 $ – $ – $ 17,785 $ 15,135 $ – $ – $ 15,135 $ 17,785 $ – $ – $ 17,785 $ 15,135 $ – $ – $ 15,135 The fair value of West Texas Intermediate (WTI) crude oil contracts in 2017 and 2016 was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in 2016 was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of crude oil derivative contracts is recorded in Sales and 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.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 are 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.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 are 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 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 contractual thresholds and time durations being achieved. As a result, the related liability as at December 31, 2022, of $192.7 million, is no longer subject to fair value measurement. The liability is included in “Other accrued liabilities” in the Consolidated Balance Sheets and the changes in fair value of the contingent consideration during 2022 were recorded in “Other (loss) income” in the Consolidated Statements of Operations.The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at December 31, 20172023 and 2016.The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 20172023 and 2016.2022. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The carrying value of Canadian government securities was determined based on cost plus earned interest. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value95MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote O – Assets and Liabilities Measured at Fair Value (Continued)hierarchy. The Company has off-balance sheet exposures relating toDecember 31, December 31, 2023 2023 2022
Amount
Value
Amount
Value(Thousands of dollars)Carrying
AmountFair
ValueCarrying
AmountFair
Value
greater than 90 days at the date of acquisition111,542 111,331 Financial liabilities: Financial liabilities: (2,916,422) (2,993,003) (2,992,567) (2,951,992) 97MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedAs a result of significantly lower commodity prices during 2016, the Company recognized $95.1 million, respectively,There were no impairment expenses incurred in pretax noncash impairment charges related primarily to producing properties. The fair value information associated with these impaired properties is presented in the following table.71,967 167,055 95,088 71,967 167,055 95,088 The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs2023 and a discount rate believed to be consistent with those used by principal market participants in the applicable region.98MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote P – ContinuedNote R – CommitmentsThe Company leases production and other facilities under operating leases. The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field and a production facility at the West Patricia field. During each of the next five years, expected future net rental payments under all operating leases are approximately $73.7 million in 2018, $65.6 million in 2019, $62.4 million in 2020, $61.3 million in 2021 and $27.8 million in 2022. Rental expense for noncancelable operating leases, including contingent payments when applicable, was $72.6 million in 2017, $77.5 million in 2016, and $111.4 million in 2015. A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note G.The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2017. These rigs will primarily be utilized for drilling operations in onshore U.S., Canada, Gulf of Mexico, and Vietnam. Future commitments under these contracts, all of which expire by 2020, total $66.6 million. Gulf of Mexico rig contracts are short term in nature and can be terminated within 30 days without cost. A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods.The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada.Canada Onshore. The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2024,2045, while the Western Canada Onshore processing contracts call for minimum monthly payments through 2035. Future2051. In the U.S. and Canada Onshore, future required minimum monthlyannual payments for the next five years are $57.8$225.9 million in 2018, $63.82024, $126.0 million in 2019, $77.92025, $114.7 million in 2020, $91.92026, $103.5 million in 20212027 and $78.5$94.4 million in 2022.2028. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total costs incurred under these service arrangements were $53.8$295.1 million in 2017, $50.32023, $216.4 million in 2016,2022 and $32.5$151.8 million in 2015.Commitments for capital expenditures were approximately $432.3$209.8 million at December 31, 2017,2023, including $197.3 million for field development and future work commitments in Malaysia, $129.4 million for development at Kaybob Duvernay in Canada, $31.8 million for work at Eagle Ford Shale, $31.3 million for exploration cost in Mexico, $24.0$173.3 million for costs to develop deepwater U.S. Gulf of Mexico fields, and $8.8 million and $6.3$13.3 million for future work commitments in VietnamEagle Ford Shale, $19.2 million for Canada and Brazil, respectively.Note SQ – 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 legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws, 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, and may be taken without full consideration of their consequences or 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.ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. 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 methane and other GHG emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. 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.96MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — ContinuedNote Q - Environmental and Other Contingencies (Continued)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. 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 recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $1.0 million threshold.99MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedThe 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(including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.In early 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified. The Company has not yet established a complete estimate of the costs to remediate the site. Based Depending on the assessments doneevolution of laws, regulations and litigation outcomes relating to date, the Company recorded $43.9 million in Other expenseclimate change, there can be no guarantee that climate change litigation will not in the 2015 Consolidated Statementsfuture materially adversely affect our results of Operations associated with the estimated costs of remediating the site. The Company has spent $39.7 million from inception to the end of 2017. 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. In the first quarter of 2018, the Company received $15.0 million in respect to an insurance claim regarding this matteroperations, cash flows and the outcome of further insurance claims by the Company is pending.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.10097MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNote TR – Common Stock Issued and OutstandingActivity in the number of shares of Common Stockcommon stock issued and outstanding for each of the three years ended December 31, 2017presented is shown below.(Number of shares outstanding)2023 2022 2021 172,202,177 172,034,711 177,499,513 15,575 368,132 158,504 478,549 2,564 8,962 8,387 Treasury shares purchased Treasury shares purchased (5,967,313) 172,572,873 172,202,177 172,034,711 1Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note JI due to withholdings for statutory income taxes owed upon issuance of shares.On August 4, 2022, the Board authorized a share repurchase program of up to $300 million of the Company’s common stock. During 2023, the Board authorized an increase to the program, bringing the total amount allowed to be repurchased under the program to $600 million. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors. The share repurchase program is a component of the Company’s capital allocation framework, the details of which can be found as part of the Company’s Form 8-K filed on August 4, 2022.During the year ended December 31, 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program for $151.2 million, including excise taxes, commissions and fees. As of December 31, 2023, the Company had $450 million remaining available to repurchase.Note US – Business SegmentsMurphy’s reportable segments are organized into geographic areas of operations. The Company’s exploration and production activity is subdivided into segments for the United States, Canada Malaysia and all other countries. Each of these segments derivesderive revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. The Company has several customersCustomers that purchase a significant portion of its oil and natural gas production. During 2017, 2016, and 2015, sales to Phillips 66 and affiliated companies represented approximately 14%, 17% and 17%, respectively,accounted for 10% or more of the Company’s total sales revenue. revenue for each of the below three years ended December 31, are shown below.2023 2022 2021 Chevron Corporation 16 % 19 % 30 % ExxonMobil Corporation 27 % 12 % N/A Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.The Company completed the sale of its U.K. downstreamNo assets during 2015. For all years presented, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the Consolidated Balance Sheets. These operationsas of December 31, 2023 and 2022. The former U.K. and U.S. downstream units have been reported as Discontinueddiscontinued operations for all periods presented in these consolidated financial statements.Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate and other activities, including interest income, miscellaneousother gains and losses (including foreign exchange gainsgains/losses and losses)realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made98MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — ContinuedNote S – Business Segments (Continued)Exploration and Production (Millions of dollars)UnitedStates 1Canada Other Total
E&PCorporate
and
OtherDiscontinued
OperationsConsolidated
TotalYear ended December 31, 2023 Segment income (loss) - including NCI 1$ 905.1 $ 41.6 $ (65.5) $ 881.2 $ (156.0) $ (1.5) $ 723.7 Revenues from external customers 2,928.3 517.5 11.0 3,456.8 3.4 — 3,460.2 Interest and other income (loss) (3.9) (1.1) (0.6) (5.6) (3.0) – (8.6) Interest expense, net of capitalization (0.1) (0.2) (0.2) (0.5) (111.9) – (112.4) Income tax expense (benefit) 232.7 11.2 (6.1) 237.8 (41.8) – 196.0 Significant noncash charges (credits) Depreciation, depletion and amortization 706.0 142.2 2.3 850.5 11.0 – 861.5 Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 0.1 – 46.1 Amortization of undeveloped leases 8.1 0.1 2.7 10.9 – – 10.9 Deferred and noncurrent income taxes 229.6 7.5 (6.7) 230.4 (50.6) – 179.8 Additions to property, plant, equipment 671.3 206.2 13.1 890.6 24.2 – 914.8 Total assets at year-end 7,107.0 2,080.0 213.3 9,400.2 365.5 0.8 9,766.6 Year ended December 31, 2022 Segment income (loss) - including NCI 1$ 1,521.9 134.2 (77.0) 1,579.1 $ (438.3) (2.1) 1,138.7 Revenues from external customers 3,461.2 762.9 23.0 4,247.1 (314.4) – 3,932.7 Interest and other income (loss) (6.6) (1.9) (0.5) (9.0) 23.3 – 14.3 Interest expense, net of capitalization (0.1) – (0.3) (0.4) (150.4) – (150.8) Income tax expense (benefit) 370.8 43.6 2.9 417.3 (107.8) – 309.5 Significant noncash charges (credits) Depreciation, depletion and amortization 617.0 141.5 5.4 763.9 12.9 – 776.8 Accretion of asset retirement obligations 36.5 9.6 0.1 46.2 – – 46.2 Amortization of undeveloped leases 8.7 0.2 4.4 13.3 – – 13.3 Deferred and noncurrent income taxes 362.7 34.8 0.6 398.1 (112.0) – 286.1 Additions to property, plant, equipment 838.6 208.5 (5.7) 1,041.4 21.9 – 1,063.3 Total assets at year-end 6,930.6 2,125.6 217.4 9,273.6 1,034.6 0.8 10,309.0 Year ended December 31, 2021 Segment income (loss) - including NCI 1$ 766.3 $ (16.1) $ (33.5) $ 716.7 $ (668.0) $ (1.2) $ 47.5 Revenues from external customers 2,337.5 476.3 4.9 2,818.7 (519.4) – 2,299.3 Interest and other income (loss) (11.6) (1.9) 3.2 (10.3) (6.5) – (16.8) Interest expense, net of capitalization – – (0.2) (0.2) (221.6) – (221.8) 99MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — ContinuedNote S – Business Segments (Continued)Exploration and Production (Millions of dollars)UnitedStates 1Canada Other Total
E&PCorporate
and
OtherDiscontinued
OperationsConsolidated
TotalIncome tax expense (benefit) 183.9 (1.7) (9.5) 172.7 (178.6) – (5.9) Significant noncash charges (credits) Impairment of assets – 171.3 18.0 189.3 7.0 – 196.3 Depreciation, depletion and amortization 616.5 163.8 1.8 782.1 13.0 – 795.1 Accretion of asset retirement obligations 36.9 9.7 – 46.6 – – 46.6 Amortization of undeveloped leases 11.1 0.2 7.6 18.9 – – 18.9 Deferred and noncurrent income taxes 176.3 (1.9) (8.0) 166.4 (170.5) – (4.1) Additions to property, plant, equipment 519.5 52.7 13.1 585.3 – – 585.3 Total assets at year-end 6,591.6 2,231.9 259.8 9,083.3 1,220.8 0.8 10,304.9 1 Includes results attributable to 2016 and 2015 Corporate Revenue from external customers to align with current period presentation (see Note A). As useda noncontrolling interest in the table on the following page, certainMP GOM.Geographic Information Certain long-lived assets at December 31 1(Millions of dollars)United
StatesCanada Other Total 2023 $ 6,555.0 $ 1,497.3 $ 172.8 $ 8,225.1 2022 6,562.8 1,499.1 166.1 8,228.0 2021 6,371.4 1,566.9 189.6 8,127.9 1 Certain long-lived assets at December 31 exclude investments, noncurrentright-of-use operating lease assets, non-current receivables, deferred tax assets and goodwill and other intangible assets.101100MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
States
E&P(2.6) 112.5 224.2 (37.5) 296.6 953.9 485.5 781.1 2,220.5 2 2.5 44.4 126.4 (36.2) 137.1 546.1 185.4 204.6 3.8 939.9 17.4 7.9 17.3 42.6 60.2 1.6 61.8 2.5 55.3 (3.7) (36.2) 17.9 534.8 267.6 16.0 37.6 856.0 5,186.2 1,725.8 1,670.1 154.2 8,736.3 (205.4) (35.9) 171.1 (54.7) (124.9) 685.7 365.3 753.4 0.2 1,804.6 (87.9) (134.3) 85.9 (18.8) (155.1) 600.5 203.2 227.7 5.9 1,037.3 17.1 13.3 16.3 46.7 38.4 4.5 0.5 43.4 95.1 95.1 (108.4) (175.8) (8.5) (18.3) (311.0) 269.8 361.3 101.4 (1.3) 731.2 5,419.0 1,559.5 2,024.7 115.7 9,118.9 (615.7) (583.4) (653.2) (158.6) (2,010.9) 1,253.6 549.7 1,131.4 2,934.7 (337.0) (188.8) (567.9) (17.3) (1,111.0) 794.9 261.9 544.9 6.2 1,607.9 20.2 12.6 15.9 48.7 59.2 14.4 1.8 75.4 329.0 683.6 1,480.6 2,493.2 (187.7) (146.0) (579.2) (4.6) (917.5) 1,263.1 184.9 244.4 39.2 1,731.6 5,717.8 2,460.6 2,537.2 147.7 10,863.3 Note T – LeasesNature of LeasesThe Company has entered into various operating leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and natural gas field equipment.Remaining lease terms range from 1 Includes Synthetic crude operationsyear to 17 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month.Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.Related ExpensesExpenses related to finance and operating leases included in 2016the Consolidated Financial Statements are as follows:Year Ended December 31, (Thousands of dollars) Financial Statement Category 2023 2022 Operating lease 1, 2Lease operating expenses $ 246,721 $ 217,038 Operating lease 2Transportation, gathering and processing 37,797 39,669 Operating lease 2Selling and general expense 9,859 8,003 Operating lease 2Other operating expense 675 510 Operating lease 2Exploration expenses 110,577 10,019 Operating lease 2Property, plant and equipment 204,595 196,829 Operating lease 2Asset retirement obligations 57,442 11,190 Finance lease Amortization of asset Depreciation, depletion and amortization 1,505 5,481 Interest on lease liabilities Interest expense, net 221 254 Sublease income Other income (1,402) (1,296) Net lease expense $ 667,990 $ 487,697 1Variable lease expenses. For the years ended December 31, 2023 and 2015. This business was sold2022, includes variable lease expenses of $36.7 million and $32.2 million, respectively, primarily related to additional volumes processed at a natural gas processing plant.2Short-term leases due within 12 months. For the year ended December 31, 2023, includes $78.2 million in June 2016.2 Includes a pretax gainLOE, $29.4 million for “Transportation, gathering and processing”, $80.3 million for “Exploration expenses, including undeveloped lease amortization”, $1.6 million in “Selling and general expenses”, $0.3 million in “Other operating expense”, $112.7 million in “Property, plant and equipment, net” and $57.4 million in “Asset retirement obligations” relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment. For the year ended December 31, 2022, includes $62.8 million in LOE, $31.5 million in “Transportation, gathering and processing”, $8.8 million for “Exploration expenses, including undeveloped lease amortization, $0.7 million in “Selling and general expenses", $0.1 million in “Other operating expense”, $125.4 million in “Property, plant and equipment, net” and $11.2 million in “Asset retirement obligations” relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment.101
States
Kingdom5,050.5 1,635.9 1,392.3 141.3 8,220.0 5,121.6 1,451.4 1,637.0 106.2 8,316.2 5,484.7 2,310.6 1,912.0 111.1 9,818.4 102NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
and
Other
Operations
Total(607.5) (0.9) (311.8) 4.6 2,225.1 7.4 7.4 181.8 181.8 245.6 382.7 17.8 957.7 42.6 61.8 242.5 260.4 14.8 870.8 1,101.7 22.9 9,860.9 (149.1) (2.0) (276.0) 6.6 1,811.2 2.9 2.9 148.2 148.2 (64.1) (219.2) 16.8 1,054.1 46.7 43.4 95.1 (76.8) (387.8) 21.9 753.1 1,149.9 27.1 10,295.9 (244.9) (15.0) (2,270.8) 6.6 2,941.3 4.0 4.0 117.4 117.4 84.5 (1,026.5) 11.9 1,619.8 48.7 75.4 2,493.2 (60.5) (978.0) 59.9 1,791.5 592.2 38.3 11,493.8
States958.3 485.7 781.1 2,225.1 692.3 365.3 753.4 0.2 1,811.2 1,260.2 549.7 1,131.4 2,941.3 Note T – Leases (Continued)103Maturity of Lease Liabilities(Thousands of dollars) Operating Leases Finance Leases Total 2024 $ 244,622 $ 1,069 $ 245,691 2025 82,596 1,069 83,665 2026 63,703 1,069 64,772 2027 62,066 1,069 63,135 2028 61,229 1,069 62,298 Remaining 499,501 265 499,766 Total future minimum lease payments 1,013,717 5,610 1,019,327 Less imputed interest (254,032) (1,372) (255,404) Present value of lease liabilities 1$ 759,685 $ 4,238 $ 763,923 1 Includes both the current and long-term portion of the lease liabilities.Lease Term and Discount RateDecember 31, 2023 December 31, 2022 Weighted average remaining lease term: Operating leases 10 years 9 years Finance leases 5 years 6 years Weighted average discount rate: Operating leases 5.9 % 5.9 % Finance leases 4.7 % 4.7 % Other InformationYear Ended December 31, (Thousands of dollars) 2023 2022 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 271,488 $ 212,061 Operating cash flows from finance leases 221 254 Financing cash flows from finance leases 622 636 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 5,923 $ 262,669 1 For the year ended December 31, 2023, right-of-use assets obtained in exchange for lease liabilities primarily includes $4.5 million related to natural gas compressor units at various U.S. Onshore locations. December 31, 2022 includes $254.0 million related to an offshore drilling rig with a lease term of 24 months.102MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information concerning some of the schedules follows:SCHEDULE 1 – SUMMARY OF TOTAL PROVED EQUIVALENT RESERVESSCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL AND SYNTHETIC OIL RESERVESSCHEDULE 23 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVESSCHEDULE 34 – SUMMARY OF PROVED NATURAL GAS RESERVESReserves of crude oil, synthetic oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year. The average prices used for 2023 were $78.22 per barrel for NYMEX crude oil (WTI) and $2.64 per MCF for natural gas (Henry Hub). The average prices used for 2022 were $93.67 per barrel for NYMEX crude oil (WTI) and $6.36 per MCF for natural gas (Henry Hub). The average prices used for 2021 were $66.56 per barrel for NYMEX crude oil (WTI) and $3.60 per MCF for natural gas (Henry Hub). Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs) and commercially available technologies to establish ‘reasonable certainty’“reasonable certainty” of economic productibility.producibility. Estimates are presented in millions of barrels of oil equivalents and dollars and billions of cubic feet with one decimal; totals within the tables may not add as a result of rounding. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiarcommon industry-accepted methods for subsurface evaluations, including performance, volumetric and analogue-basedanalog-based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.Prior to its disposition in 2016, Murphy included synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of natural gas liquids.All crude oil, and synthetic reserves, natural gas liquidsliquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.104103MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedAll proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. At December 31, 2017, liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 52.2 million barrels and 491.3 billion cubic feet (BCF), respectively. At December 31, 2017, approximately 26.7 BCF of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet. Sales price for other natural gas produced in Malaysia is based on market-driven prices.SCHEDULE 67 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVESGAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result the company’s statutory U.S. tax rate will be 21% beginning in 2018, a decrease from the previous rate of 35%.The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.Schedule 67 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2017.2023.105104MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 1 – Summary of Total Proved Crude Oil and Synthetic OilEquivalent Reserves Based on Average Prices20142020 – 2017
Synthetic
Oil
Oil 1
States
undeveloped crude oil /
synthetic oil reserves:441.8 336.2 204.9 37.4 93.9 105.6 5.3 (8.2) (7.6) (4.8) 4.2 13.5 2.4 2.4 2.4 63.8 63.8 63.8 (11.0) (11.0) (11.0) (46.1) (41.8) (22.2) (4.7) (14.9) (4.3) 456.2 341.4 238.9 27.9 74.6 114.8 (5.8) (5.8) (10.9) 2.5 2.6 11.0 11.0 8.6 2.4 26.3 26.3 26.3 (121.0) (7.8) (4.5) (3.3) (113.2) (37.7) (36.1) (17.7) (4.5) (13.9) (1.6) 329.0 329.0 214.4 48.9 65.7 (0.0) (6.0) (6.0) (4.7) 2.3 (3.6) 2.0 2.0 2.0 31.6 31.6 27.2 4.4 4.7 4.7 4.7 (33.2) (33.2) (16.9) (4.1) (12.2) 328.1 328.1 224.7 51.5 51.9
oil/ synthetic oil reserves:324.1 218.5 106.2 32.4 79.9 105.6 326.6 211.8 125.9 23.8 62.1 114.8 184.9 184.9 113.9 19.2 51.8 185.5 185.5 126.3 21.9 37.3
oil reserves:117.7 117.7 98.7 5.0 14.0 129.6 129.6 113.0 4.1 12.5 144.1 144.1 100.5 29.7 13.9 142.6 142.6 98.4 29.6 14.6 Equivalents (Millions of barrels of oil equivalent)Total United
StatesCanada Other Proved developed and undeveloped reserves: December 31, 2020 714.9 328.5 386.4 – Revisions of previous estimates (52.9) 35.6 (89.3) 0.8 Extensions and discoveries 109.4 18.2 91.3 – Purchases of properties 7.4 1.6 5.8 – Sales of properties (0.7) – (0.7) – Production (61.1) (40.4) (20.6) (0.1) December 31, 2021 716.9 343.4 372.8 0.7 Revisions of previous estimates (23.6) 29.0 (52.8) 0.2 Improved recovery 5.3 5.3 – – Extensions and discoveries 80.1 20.6 59.5 – Purchases of properties 5.0 5.0 – – Sales of properties (4.4) (4.4) – – Production (63.9) (41.9) (21.7) (0.3) December 31, 2022 715.4 357.0 357.8 0.6 Revisions of previous estimates (13.3) (13.3) 0.2 (0.2) Improved recovery 0.4 – 0.4 – Extensions and discoveries 112.6 12.7 87.3 12.6 Sales of properties (5.2) – (5.2) – Production (70.4) (45.3) (25.0) (0.1) December 31, 2023 ¹ 739.5 311.1 415.5 12.9 Proved developed reserves: December 31, 2020 410.8 230.3 180.5 – December 31, 2021 419.2 241.9 176.8 0.6 December 31, 2022 436.0 264.2 171.3 0.5 December 31, 2023 ² 425.5 223.2 202.0 0.3 Proved undeveloped reserves: December 31, 2020 304.1 98.2 205.9 – December 31, 2021 297.7 101.6 196.0 0.1 December 31, 2022 279.4 92.8 186.5 0.1 December 31, 2023 ³ 314.0 87.9 213.5 12.6 1 All synthetic Includes proved reserves of 15.5 MMBOE, consisting of 14.0 MMBBL oil, operations were sold0.6 MMBBL NGLs and 5.3 BCF natural gas attributable to the noncontrolling interest in June 2016.MP GOM.1063 Includes proved undeveloped reserves of 2.7 MMBOE, consisting of 2.3 MMBBL oil, 0.1 MMBBL NGLs and 1.5 BCF natural gas attributable to the noncontrolling interest in MP GOM.4 Totals within the tables may not add as a result of rounding.105MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 1 – Summary of Total Proved Crude Oil and Synthetic OilEquivalent Reserves Based on Average Prices20142020 – 2017 – Continued20172023 (Continued)2023 Comments for Proved Crude OilEquivalent Reserves ChangesRevisions of previous estimate – estimates - The 2017 negative crude oil revisionequivalent reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. was primarily attributable toand performance adjustments in Tupper Montney and the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields,Shale. These negative revisions were partially offset by improved Eagle Ford Shale costspositive revisions due to reduced royalty rates and performance resultsdelayed royalty incentive payouts resulting from lower commodity prices in the Gulf of Mexico. The positive Canadian oilTupper Montney.Extensions and discoveries - In 2023, proved equivalent reserves revisionswere added for drilling and expansion activities predominantly in 2017 resulted from improved performanceCanada at Tupper Montney, assets in Western Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.Improved recovery – The 2017 Malaysia crude oil proved reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent within the reallocationU.S., and Other international.Purchases and sales of capitalproperties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its Placid Montney assets in Canada.2022 Comments for Proved Equivalent Reserves ChangesRevisions of previous estimates - The equivalent reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher performing drilling areas movingcommodity prices in Tupper Montney. These negative revisions were partially offset by positive well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activitiesperformance in the MontneyU.S. Gulf of Mexico.Extensions and Duvernay. Proved oildiscoveries - In 2022, proved equivalent reserves were also added for drilling and expansion activities predominantly in Canada at Tupper Montney and Kaybob Duvernay as well as in the U.S. offshore.Purchases and sales of properties –- In 2017,2022, the Company acquired greaterincremental working interests in two of its operatedproducing fields in the U.S. Gulf of Mexico fields. In U.S. onshore, the Company acquired acreageand divested working interests in one field in the Permian areaU.S. Gulf of west Texas. AdditionalMexico and a portion of Eagle Ford Shale acreage was acquired through joint venture agreements with other operators within its core acreage position. 2016Shale.2021 Comments for Proved Crude Oil and Synthetic OilEquivalent Reserves ChangesRevisions of previous estimate – estimates -The 2016equivalent reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative crude oil revisionrevisions were partially offset by positive revisions in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumesfrom higher commodity prices, which partially reversed the 2020 capital expenditure reduction and reducedimproved well performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the U.S. Gulf of Mexico. The positive Canadian oil reserves revisions in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling. The positive revisions for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis.Extensions and discoveries –- In 2016,2021, proved oilequivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. for drilling activities inat the Eagle Ford Shale and deeper oil-water contacts realized at a field in Malaysia.Purchases and sales of properties –- In 2016,2021, the Company’s Canadian subsidiaryCompany acquired incremental working interests in the Kaybob DuvernayTerra Nova offshore Canada and liquids rich Placid Montney areas. The crude oil reserves are all associated with the Kaybob Duvernay area.Sales of properties – Inin the U.S., proved oil reserves were reduced following the sale Gulf of certain non-core Eagle Ford Shale acreage. In Canada, the Company sold its interests in both a heavy oil field and a synthetic oil project.107106MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued2015 Comments forSchedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2020 – 2023(Millions of barrels)Total United
StatesCanada Other Proved developed and undeveloped crude oil reserves: December 31, 2020 266.5 240.6 25.9 – Revisions of previous estimates 39.3 31.1 7.5 0.7 Extensions and discoveries 14.1 13.5 0.6 – Purchases of properties 6.4 1.3 5.2 – Production (34.9) (31.5) (3.3) (0.1) December 31, 2021 291.5 255.0 35.9 0.6 Revisions of previous estimates 23.4 19.9 3.3 0.2 Improved recovery 4.7 4.7 – – Extensions and discoveries 18.9 16.1 2.8 – Purchases of properties 4.2 4.2 – – Sales of properties (3.6) (3.6) – – Production (35.5) (32.7) (2.5) (0.3) December 31, 2022 303.6 263.6 39.5 0.5 Revisions of previous estimates (10.8) (8.9) (1.8) (0.1) Improved recovery 0.4 – 0.4 – Extensions and discoveries 22.5 8.9 1.5 12.1 Sales of properties (2.0) – (2.0) – Production (37.9) (35.6) (2.2) (0.1) December 31, 2023 ¹ 275.8 228.0 35.4 12.4 Proved developed crude oil reserves: December 31, 2020 179.8 161.4 18.4 – December 31, 2021 191.5 174.9 16.0 0.5 December 31, 2022 209.0 194.4 14.2 0.4 December 31, 2023 ² 186.3 163.7 22.3 0.3 Proved undeveloped crude oil reserves: December 31, 2020 86.7 79.2 7.5 – December 31, 2021 99.9 80.0 19.8 0.1 December 31, 2022 94.6 69.2 25.3 0.1 December 31, 2023 ³ 89.5 64.3 13.1 12.1 1 Includes total proved reserves of 14.0 MMBBL for Total and Synthetic Oil Reserves ChangesRevisions of previous estimate – The 2015 negative crude oil revision in the U.S. was primarilyUnited States attributable to impactsthe noncontrolling interest in MP GOM.2 Includes proved developed reserves of lower price on Eagle Ford Shale volumes, partially offset by improved Eagle Ford Shale performance, improved Eagle Ford Shale lifting costs,11.7 MMBBL for Total and drilling activityUnited States attributable to the noncontrolling interest in MP GOM.3 Includes proved undeveloped reserves of 2.3 MMBBL for Total and United States attributable to the Gulf of Mexico. The negative Canadian conventional oil reserves revisionnoncontrolling interest in 2015 wasMP GOM.4 Totals within the tables may not add as a result of lower heavy oil prices partially offset by increases at both Hibernia and Terra Nova due to development drilling and lower government royalty effects. The positive synthetic oil revision in the current period is due predominantly to lower government royalty effects due to lower oil prices. The positive revision for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the termsrounding.107108SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2020 – 2023 (Continued)2023 Comments for Proved Crude Oil Reserves ChangesRevisions of previous estimates - The negative crude oil reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale and the U.S. Gulf of Mexico.Extensions and discoveries - In 2023, proved oil reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale and Other international.Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its Placid Montney assets in Canada.2022 Comments for Proved Crude Oil Reserves ChangesRevisions of previous estimates - The positive crude oil reserves revisions in 2022 resulted predominantly from improved well performance in the U.S. Gulf of Mexico and impacts of higher commodity prices in the U.S.Extensions and discoveries - In 2022, proved oil reserves were added for drilling and expansion activities predominantly in the U.S. Gulf of Mexico and the Eagle Ford Shale.Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S. Gulf of Mexico and divested working interests in one field in the U.S. Gulf of Mexico and a portion of the Eagle Ford Shale.2021 Comments for Proved Crude Oil Reserves ChangesRevisions of previous estimates - The positive crude oil reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices in the U.S., which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S. Gulf of Mexico.Extensions and discoveries - In 2021, proved oil reserves were added for drilling and expansion activities predominantly in the U.S. at the Eagle Ford Shale and the Gulf of Mexico.Purchases and sales of properties - In 2021, the Company acquired incremental working interests in Terra Nova offshore Canada and one field in the U.S. Gulf of Mexico.108MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 3 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices 20142020 – 2017
States30.6 29.1 0.7 0.8 2.0 2.2 (0.3) 0.1 7.6 7.6 (0.1) (0.1) (3.7) (3.5) (0.2) 36.4 35.4 0.4 0.6 1.6 1.2 0.2 0.2 2.9 2.8 0.1 5.1 5.1 (3.5) (3.0) (0.2) (0.3) 42.5 36.4 5.6 0.5 1.3 2.0 (0.6) (0.1) 7.8 7.0 0.8 0.5 0.5 (3.2) (2.9) (0.2) (0.1) 48.9 43.0 5.6 0.3 17.5 16.5 0.2 0.8 21.6 20.7 0.3 0.6 22.2 20.8 0.9 0.5 24.6 23.3 1.0 0.3 13.1 12.6 0.5 14.8 14.7 0.1 20.3 15.6 4.7 24.3 19.7 4.6 (Millions of barrels)Total United
StatesCanada Other Proved developed and undeveloped NGL reserves: December 31, 2020 38.2 34.6 3.6 – Revisions of previous estimates 1.4 1.4 – – Extensions and discoveries 2.5 2.4 0.1 – Purchase of properties 0.1 0.1 – – Production (3.8) (3.4) (0.4) – December 31, 2021 38.4 35.1 3.3 – Revisions of previous estimates 4.4 3.9 0.5 – Improved recovery 0.2 0.2 – – Extensions and discoveries 2.5 1.9 0.6 – Purchases of properties 0.3 0.3 – – Sales of properties (0.2) (0.2) – – Production (3.9) (3.6) (0.3) – December 31, 2022 41.7 37.6 4.1 – Revisions of previous estimates (1.4) (1.2) (0.2) – Extensions and discoveries 2.0 1.7 0.3 – Sales of properties (0.6) – (0.6) – Production (4.1) (3.8) (0.3) – December 31, 2023 ¹ 37.6 34.3 3.3 – Proved developed NGL reserves: December 31, 2020 28.7 25.5 3.2 – December 31, 2021 28.4 25.6 2.8 – December 31, 2022 29.7 27.4 2.3 – December 31, 2023 ² 25.9 24.1 1.8 – Proved undeveloped NGL reserves: December 31, 2020 9.5 9.1 0.4 – December 31, 2021 10.0 9.5 0.5 – December 31, 2022 12.0 10.2 1.8 – December 31, 2023 ³ 11.7 10.2 1.5 – 1 Includes total proved reserves of 0.6 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.2 Includes proved developed reserves of 0.5 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.3 Includes proved undeveloped reserves of 0.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.109MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 23 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices20142020 – 2017 – Continued20172023 (Continued)2023 Comments for Proved Natural Gas Liquids Reserves ChangesRevisions of previous estimates – - The positive 2017negative NGL proved reserves revisionrevisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.Extensions and discoveries – Proved NGL reserves were added primarily from drilling activitiesperformance adjustments in the Eagle Ford Shale area concurrent withShale. These revisions were partially offset by improvements in the reallocationU.S. Gulf of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves.Purchase of properties – Mexico.Extensions and discoveries - In U.S.,2023, proved NGL reserves were added followingfor drilling and expansion activities predominantly in the acquisition of acreage in bothU.S. at the Eagle Ford ShaleShale.Purchases and Permian areas, and increasedsales of properties - In 2023, the Company divested a portion of its working interest in two Gulfthe Kaybob Duvernay and all of Mexico fields.2016its Placid Montney assets in Canada.2022 Comments for Proved Natural Gas Liquids Reserves ChangesRevisions of previous estimates –- The positive 2016 NGL proved reserves revision was primarilyrevisions in 2022 resulted predominantly from improved well performance in the U.S. Gulf of Mexico and the Eagle Ford Shale, area based on an updated ratio of oil to gas production.Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area.Purchase of properties – -Canada,2022, proved NGL reserves were added followingfor drilling and expansion activities predominantly in the acquisitionU.S. Gulf of acreageMexico and the Eagle Ford Shale, as well as in bothCanada at Tupper Montney and Kaybob Duvernay.Purchases and sales of properties - In 2022, the Kabob DuvernayCompany acquired incremental working interests in two producing fields in the U.S. Gulf of Mexico and liquids rich Placid Montney areas.2015divested working interests in one field in the U.S. Gulf of Mexico and a portion of the Eagle Ford Shale.2021 Comments for Proved Natural Gas Liquids Reserves ChangesRevisions of previous estimates –-The positive 2015 NGL proved reserves revisionrevisions in 2021 resulted predominantly from impacts of higher commodity prices, which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S. was primarily in the Eagle Ford Shale area based on improved performance.Extensions and discoveries – -In 2015,2021, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. added NGL reserves primarily for additional drilling activitiesat Eagle Ford Shale.Purchases and sales of properties - In 2021, the Company acquired incremental working interests in the Eagle Ford Shale.SalesU.S. Gulf of properties – The Company sold 10%Mexico.110110SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 34 – Summary of Proved Natural Gas Reserves Based on Average Prices for 20142020 – 20172023
States
natural gas reserves:1,704.7 226.3 842.8 635.6 53.5 (5.2) 18.9 39.8 1.8 1.8 162.9 43.2 119.7 (78.0) (78.0) (156.1) (31.9) (71.8) (52.4) 1,688.8 232.4 909.6 546.8 43.3 0.1 45.3 (2.1) 164.2 6.4 120.2 37.6 122.3 122.3 (2.2) (0.1) (2.1) (138.4) (19.4) (76.4) (42.6) 1,878.0 219.4 1,118.9 539.7 (5.4) (16.0) 19.4 (8.8) 190.6 32.2 156.7 1.7 4.0 4.0 (140.1) (16.3) (82.6) (41.2) 1,927.1 223.3 1,212.4 491.4 812.1 145.6 467.4 199.1 783.5 148.3 453.5 181.7 818.1 138.7 498.9 180.5 819.3 127.7 547.0 144.6 892.6 80.7 375.4 436.5 905.3 84.1 456.1 365.1 1,059.9 80.7 620.0 359.2 1,107.8 95.6 665.5 346.7 (Billions of cubic feet)Total United
StatesCanada Other Proved developed and undeveloped natural gas reserves: December 31, 2020 2,461.0 319.5 2,141.5 – Revisions of previous estimates (562.1) 18.7 (581.0) 0.2 Extensions and discoveries 556.7 13.5 543.2 – Purchases of properties 5.4 1.5 3.9 – Sales of properties (4.4) – (4.4) – Production (134.2) (32.8) (101.4) – December 31, 2021 2,322.3 320.3 2,001.8 0.2 Revisions of previous estimates (309.8) 30.7 (340.5) – Improved recovery 2.6 2.6 – – Extensions and discoveries 352.4 15.7 336.7 – Purchases of properties 2.9 2.9 – – Sale of properties (3.6) (3.6) – – Production (146.9) (33.7) (113.2) – December 31, 2022 2,219.9 334.9 1,884.8 0.2 Revisions of previous estimates (6.9) (19.0) 12.1 – Extensions and discoveries 528.9 12.3 513.8 2.8 Sales of properties (15.6) – (15.6) – Production (170.1) (35.1) (135.0) – December 31, 2023 1,42,556.2 293.1 2,260.1 3.0 Proved developed natural gas reserves: December 31, 2020 1,213.8 260.2 953.6 – December 31, 2021 1,196.0 248.1 947.7 0.2 December 31, 2022 1,183.1 254.1 928.8 0.2 December 31, 2023 2,41,279.3 212.4 1,066.7 0.2 Proved undeveloped natural gas reserves: December 31, 2020 1,247.2 59.3 1,187.9 – December 31, 2021 1,126.4 72.2 1,054.1 – December 31, 2022 1,036.8 80.8 956.0 – December 31, 2023 ³ 1,276.9 80.7 1,193.4 2.8 1 Includes total proved reserves of 5.3 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.2 Includes proved developed reserves of 3.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.3 Includes proved undeveloped reserves of 1.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.4 Includes proved natural gas reserves to be consumed in operations as fuel of 71.3 BCF, 41.9 BCF and 2.8 BCF for the U.S. Canada and Other, respectively, with 1.2 BCF attributable to the noncontrolling interest in MP GOM.5 Totals within the tables may not add as a result of rounding.111MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 34 – Summary of Proved Natural Gas Reserves Based on Average Prices for 20142016 – 2017 – Continued20172019 (Continued)2023 Comments for Proved Natural Gas Reserves ChangesRevisions of previous estimates – In the U.S., the - The negative natural gas revision was primarily due to shuttingreserves revisions in a gas well located2023 resulted predominantly from lower commodity prices in the Gulf of Mexico due to early water break through,U.S. and performance adjustments in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5-year development window as capital was reallocated to higher performing drilling locations withinTupper Montney and the Eagle Ford Shale. TheThese negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices, offsettingrevisions were partially offset by positive performance revisions at the Company’s Sarawak projects. The 2017 positive natural gas revisions in the U.S. Gulf of Mexico, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in Western Canada. Extensions and discoveries – - In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in Western Canada. In Malaysia,2023, proved natural gas reserves were added for drilling and expansion activities predominantly in Sarawak from field development activities.PurchaseCanada at Tupper Montney.Purchases and sales of properties – - In 2023, the U.S.,Company divested a portion of its working interest in the Kaybob Duvernay and all of its Placid Montney assets in Canada.2022 Comments for Proved Natural Gas Reserves ChangesRevisions of previous estimates -The negative natural gas reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Canada at Tupper Montney.Extensions and discoveries - In 2022, proved natural gas reserves were added followingfor drilling and expansion activities predominantly in Canada at Tupper Montney, as well as in the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in twoU.S. Gulf of Mexico fields.2016and Eagle Ford Shale.Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S. Gulf of Mexico and divested working interests in one field in the U.S. Gulf of Mexico and a portion of Eagle Ford Shale.2021 Comments for Proved Natural Gas Reserves ChangesRevisions of previous estimates – The 2016 positive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada. -The negative revision for natural gas reserves revisions in Malaysia was primarily attributable2021 resulted predominantly from accelerated royalty incentive payouts due to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans.Extensions and discoveries –- In 2016, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper area. In Malaysia,2021, proved natural gasequivalent reserves were added for drilling and expansion activities predominantly in Block HCanada at Tupper Montney, as the Permai field was added to the field development plan.Purchase of properties – In Canada, proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas.Sales of properties – Proved natural gas reserves were reduced following the sale of certain non-core Eagle Ford Shale acreagewell as in the U.S. and the associated gas related to the sale of a heavy oil field in Canada.2015 Comments for Proved Natural Gas Reserves ChangesRevisions of previous estimates – The 2015 negative natural gas revision in the U.S. was primarily attributable to performance declines in certain fields in the Gulf of Mexico offset in part by the overall positive performance inat the Eagle Ford Shale area. The positive revisions inand the Gulf of Mexico.Purchases and sales of properties - In 2021, the Company acquired incremental working interests at Terra Nova offshore Canada were attributable to updated well type curves and field development techniques in the Montney areaU.S. Gulf of Western Canada. The positive revision for natural gas reserves in Malaysia was attributable to lower government entitlement under the termsMexico.112112SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 45 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
States50.4 13.0 63.4 7.7 7.7 58.1 13.0 71.1 13.7 0.6 (8.9) 73.8 79.2 508.4 273.8 35.7 1.1 819.0 580.2 274.4 26.8 87.9 969.3 (1.9) 0.7 (3.0) (4.2) 9.7 0.5 1.7 53.3 65.2 7.8 0.5 2.4 50.3 61.0 572.4 273.9 24.4 37.6 908.3 18.6 18.6 206.7 206.7 18.6 206.7 225.3 18.5 3.6 6.0 42.0 70.1 239.7 165.1 102.9 0.3 508.0 276.8 375.4 108.9 42.3 803.4 0.4 4.5 10.2 15.1 5.7 3.6 0.7 33.4 43.4 6.1 3.6 5.2 43.6 58.5 270.7 371.8 103.7 (1.3) 744.9 10.1 2.5 12.6 10.1 2.5 12.6 166.8 0.7 69.0 135.4 371.9 1,375.1 231.5 210.0 2.8 1,819.4 1,552.0 234.7 279.0 138.2 2,203.9 241.3 29.7 25.8 296.8 16.9 0.7 7.9 73.2 98.7 258.2 0.7 37.6 99.0 395.5 1,293.8 234.0 241.4 39.2 1,808.4 (Millions of dollars)United
StatesCanada 1Other Total Year ended December 31, 2023 Property acquisition costs Unproved $ – $ – $ 8.5 $ 8.5 Proved 12.8 – 14.3 27.1 Total acquisition costs 12.8 – 22.8 35.6 Exploration costs 157.8 0.4 39.9 198.1 Development costs 667.2 206.2 7.4 880.8 Total costs incurred 837.8 206.6 70.1 1,114.5 Charged to expense Dry hole expense 153.1 – 16.7 169.8 Geophysical and other costs 13.4 0.4 40.3 54.1 Total charged to expense 166.5 0.4 57.0 223.9 Property additions $ 671.3 $ 206.2 $ 13.1 $ 890.6 Year ended December 31, 2022 Property acquisition costs Unproved $ 1.8 $ – $ – $ 1.8 Proved 128.5 – – 128.5 Total acquisition costs 130.3 – – 130.3 Exploration costs 42.2 0.8 70.3 113.3 Development costs 704.9 208.5 4.3 917.7 Total costs incurred 877.4 209.3 74.6 1,161.3 Charged to expense Dry hole expense 23.0 – 59.1 82.1 Geophysical and other costs 15.8 0.8 21.1 37.7 Total charged to expense 38.8 0.8 80.2 119.8 Property additions $ 838.6 $ 208.5 $ (5.6) $ 1,041.5 Year ended December 31, 2021 Property acquisition costs Unproved $ 8.8 $ – $ – $ 8.8 Proved 19.9 (20.4) – (0.5) Total acquisition costs 28.7 (20.4) – 8.3 Exploration costs 31.7 0.4 30.1 62.2 Development costs 513.2 102.4 3.7 619.3 Total costs incurred 573.6 82.4 33.8 689.8 Charged to expense Dry hole expense 17.3 – – 17.3 Geophysical and other costs 13.1 0.4 19.3 32.8 Total charged to expense 30.4 0.4 19.3 50.1 Property additions $ 543.2 $ 82.0 $ 14.5 $ 639.7 1 Includes noncash2021 Canada proved property acquisitions represents cash received from divesting partners on acquisition of an additional 7.525% working interest at Terra Nova as part of the sanction of an asset retirement costs as follows:life extension project.37.6 6.3 8.4 52.3 37.6 6.3 8.4 52.3 0.9 10.5 2.3 13.7 0.9 10.5 2.3 13.7 30.7 49.1 (3.0) 76.8 30.7 49.1 (3.0) 76.8 113113MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 56 – Results of Operations for Oil and Natural Gas Producing Activities 1913.3 203.7 639.9 1,756.9 37.9 155.1 138.2 331.2 951.2 358.8 778.1 2,088.1 2.7 126.7 3.0 132.4 953.9 485.5 781.1 2,220.5 198.5 101.1 168.8 468.4 42.2 1.5 43.7 7.8 0.5 2.4 50.3 61.0 60.2 1.6 61.8 546.1 185.4 204.6 3.8 939.9 17.4 7.9 17.3 42.6 15.0 15.0 61.8 28.3 14.0 19.6 123.7 20.0 2.3 8.4 30.7 954.0 328.6 430.5 73.7 1,786.8 (0.1) 156.9 350.6 (73.7) 433.7 2.5 44.4 126.4 (36.2) 137.1 (2.6) 112.5 224.2 (37.5) 296.6 650.7 171.7 60.7 623.7 1,506.8 35.1 130.0 127.6 292.7 685.8 301.7 60.7 751.3 1,799.5 (0.1) (0.7) 3.6 2.1 0.2 5.1 685.7 301.0 64.3 753.4 0.2 1,804.6 218.6 102.6 69.8 168.4 559.4 37.0 4.3 2.5 43.8 6.1 3.6 5.2 43.6 58.5 38.4 4.5 0.5 43.4 600.5 186.7 16.5 227.7 5.9 1,037.3 17.1 10.9 2.4 16.3 46.7 95.1 95.1 39.1 39.1 68.8 28.6 0.5 15.9 33.6 147.4 (7.5) 7.5 23.8 (9.9) 13.9 979.0 443.8 91.7 496.4 73.7 2,084.6 (293.3) (142.8) (27.4) 257.0 (73.5) (280.0) (87.9) (58.9) (75.4) 85.9 (18.8) (155.1) (205.4) (83.9) 48.0 171.1 (54.7) (124.9) (Millions of dollars)United
StatesCanada Other Total Year ended December 31, 2023 Revenues Crude oil and natural gas liquids sales $ 2,829.1 $ 165.7 $ 11.0 $ 3,005.8 Natural gas sales 92.7 278.2 – 370.9 Sales of purchased natural gas – 72.2 – 72.2 Total oil and natural gas revenues 2,921.8 516.1 11.0 3,448.9 Other operating revenues 6.5 1.4 – 7.9 Total revenues 2,928.3 517.5 11.0 3,456.8 Costs and expenses Lease operating expenses 630.7 151.8 1.9 784.4 Severance and ad valorem taxes 41.4 1.4 – 42.8 Transportation, gathering and processing 157.0 76.0 – 233.0 Costs of purchased natural gas – 51.7 – 51.7 Exploration costs charged to expense 166.5 0.4 57.0 223.9 Undeveloped lease amortization 8.1 0.1 2.7 10.9 Depreciation, depletion and amortization 706.0 142.2 2.3 850.5 Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 Selling and general expenses 11.8 16.5 9.4 37.7 Other expenses (benefits) 31.2 16.8 8.9 56.9 Total costs and expenses 1,790.5 464.7 82.6 2,337.8 Results of operations before taxes 1,137.8 52.8 (71.6) 1,119.0 Income tax expense (benefit) 232.7 11.2 (6.1) 237.8 Results of operations $ 905.1 $ 41.6 $ (65.5) $ 881.2 Year ended December 31, 2022 Revenues Crude oil and natural gas liquids sales $ 3,210.3 $ 267.5 $ 22.8 $ 3,500.6 Natural gas sales 225.3 312.6 – 537.9 Sales of purchased natural gas 0.2 181.5 – 181.7 Total oil and natural gas revenues 3,435.8 761.6 22.8 4,220.2 Other operating revenues 25.4 1.3 – 26.7 Total revenues 3,461.2 762.9 22.8 4,246.9 Costs and expenses Lease operating expenses 522.7 155.1 1.5 679.3 Severance and ad valorem taxes 55.7 1.3 – 57.0 Transportation, gathering and processing 142.2 70.5 – 212.7 Costs of purchased natural gas 0.2 171.8 – 172.0 Exploration costs charged to expense 38.8 0.8 80.2 119.8 Undeveloped lease amortization 8.7 0.2 4.4 13.3 Depreciation, depletion and amortization 617.0 141.5 5.4 763.9 Accretion of asset retirement obligations 36.5 9.6 0.1 46.2 Selling and general expenses 20.4 21.9 2.2 44.5 Other expenses 126.3 12.4 3.1 141.8 Total costs and expenses 1,568.5 585.1 96.9 2,250.5 Results of operations before taxes 1,892.7 177.8 (74.1) 1,996.4 Income tax expense (benefit) 370.8 43.6 2.9 417.3 Results of operations $ 1,521.9 $ 134.2 $ (77.0) $ 1,579.1 1Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.114MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 56 – Results of Operations for Oil and Natural Gas Producing Activities 1 – Continued(Continued)1,176.9 181.0 203.0 790.6 2,351.5 70.4 167.7 185.4 423.5 1,247.3 348.7 203.0 976.0 2,775.0 6.3 (2.4) 0.4 155.4 159.7 1,253.6 346.3 203.4 1,131.4 2,934.7 312.0 102.4 166.0 251.9 832.3 55.9 4.8 5.1 65.8 258.2 0.7 37.6 99.0 395.5 59.2 14.4 1.8 75.4 794.9 211.2 50.7 544.9 6.2 1,607.9 20.2 7.2 5.4 15.9 48.7 329.0 683.6 1,480.6 2,493.2 88.2 25.5 1.0 5.7 56.8 177.2 288.7 43.9 15.9 12.1 360.6 2,206.3 1,093.7 228.2 2,352.5 175.9 6,056.6 (952.7) (747.4) (24.8) (1,221.1) (175.9) (3,121.9) (337.0) (191.2) 2.4 (567.9) (17.3) (1,111.0) (615.7) (556.2) (27.2) (653.2) (158.6) (2,010.9) (Millions of dollars)United
StatesCanada Other Total Year ended December 31, 2021 Revenues Crude oil and natural gas liquids sales $ 2,199.7 $ 228.9 $ 4.9 $ 2,433.5 Natural gas sales 121.8 245.9 – 367.7 Total oil and natural gas revenues 2,321.5 474.8 4.9 2,801.2 Other operating revenues 16.0 1.5 – 17.5 Total revenues 2,337.5 476.3 4.9 2,818.7 Costs and expenses Lease operating expenses 406.4 136.3 (3.2) 539.5 Severance and ad valorem taxes 39.6 1.6 – 41.2 Transportation, gathering and processing 126.5 60.5 – 187.0 Exploration costs charged to expense 30.4 0.4 19.3 50.1 Undeveloped lease amortization 11.1 0.2 7.6 18.9 Depreciation, depletion and amortization 616.5 163.8 1.8 782.1 Accretion of asset retirement obligations 36.9 9.7 – 46.6 Impairment of assets – 171.3 18.0 189.3 Selling and general expenses 20.5 16.5 6.6 43.6 Other expenses 99.4 (66.2) (2.2) 31.0 Total costs and expenses 1,387.3 494.1 47.9 1,929.3 Results of operations before taxes 950.2 (17.8) (43.0) 889.4 Income tax expense (benefit) 183.9 (1.7) (9.5) 172.7 Results of operations $ 766.3 $ (16.1) $ (33.5) $ 716.7 1Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.115MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 67 – Standardized Measure of Discounted Future Net Cash Flows Relating toProved Oil and Natural Gas Reserves1
States(Millions of dollars)United
StatesCanada Other Total December 31, 2023 December 31, 2023 12,885.8�� 4,714.3 4,392.0 21,992.1 (2,079.5) (1,081.7) (632.3) (3,793.5) (4,765.3) (2,507.4) (2,305.0) (9,577.7) (893.7) (161.1) (232.2) (1,287.0) 5,147.3 964.1 1,222.5 7,333.9
of cash flows(2,698.2) (394.6) (318.2) (3,411.0)
future net cash flows2,449.1 569.5 904.3 3,922.9 December 31, 2022 Future cash inflows Future cash inflows 9,477.9 3,752.7 4,318.7 17,549.3 (1,691.1) (1,143.6) (763.8) (3,598.5) (3,981.6) (2,329.7) (2,661.2) (8,972.5) (118.9) (81.3) (73.3) (273.5) 3,686.3 198.1 820.4 4,704.8
of cash flows(1,799.5) (95.0) (230.3) (2,124.8)
future net cash flows1,886.8 103.1 590.1 2,580.0 December 31, 2021 Future cash inflows Future cash inflows 12,373.9 8,922.0 6,143.1 27,439.0 (2,620.5) (1,145.4) (957.8) (4,723.7) (4,955.4) (5,892.7) (3,290.5) (14,138.6) (339.7) (504.8) (216.2) (1,060.7) 4,458.3 1,379.1 1,678.6 7,516.0
of cash flows(2,430.0) (666.8) (560.1) (3,656.9)
future net cash flows2,028.3 712.3 1,118.5 3,859.1 2 Totals within the table may not add as a result of rounding.116MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 67 – Standardized Measure of Discounted Future Net Cash Flows Relating toProved Oil and Natural Gas Reserves – ContinuedFollowingThe following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shoshown.(Millions of dollars)2023 2022 2021 Net changes in prices and production costs 2$ (5,845.6) $ 4,812.2 $ 5,962.1 Net changes in development costs (78.8) (531.1) (503.6) Sales and transfers of oil and natural gas produced, net of production costs (2,264.8) (2,917.4) (2,220.5) Net change due to extensions and discoveries 770.4 1,223.5 908.5 Net change due to purchases and sales of proved reserves (96.1) 102.1 63.1 Development costs incurred 703.7 769.3 619.3 Accretion of discount 1,393.3 802.6 267.2 Revisions of previous quantity estimates (771.5) 1,652.9 277.1 Net change in income taxes 1,229.6 (1,399.9) (692.8) Net increase (decrease) (4,959.8) 4,514.2 4,680.4 Standardized measure at January 1 11,813.2 7,299.0 2,618.6 Standardized measure at December 31 $ 6,853.4 $ 11,813.2 $ 7,299.0 1 Includes noncontrolling interest in MP GOM.2 The average prices used for 2023 were $78.22 per barrel for NYMEX crude oil (WTI) and $2.64 per MCF for natural gas (Henry Hub). The average prices used for 2022 were $93.67 per barrel for NYMEX crude oil (WTI) and $6.36 per MCF for natural gas (Henry Hub). The average prices used for 2021 were $66.56 per barrel for NYMEX crude oil (WTI) and $3.60 per MCF for natural gas (Henry Hub).1172,428.4 (1,476.1) (11,365.5) (724.4) 544.9 591.4 (1,576.0) (1,196.3) (1,876.9) 807.9 280.5 1,145.8 85.9 (583.4) (287.4) 802.7 479.6 1,725.4 270.9 428.1 1,289.5 (109.5) (49.2) 163.3 (643.0) 292.8 2,568.3 1,342.9 (1,279.1) (6,046.1) 2,580.0 3,859.1 9,905.2 3,922.9 2,580.0 3,859.1 SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – ContinuedSchedule 78 – Capitalized Costs Relating to Oil and Natural Gas Producing Activities
States360.9 286.8 20.5 162.1 830.3 9,606.4 3,603.4 6,139.7 19,349.5 9,967.3 3,890.2 6,160.2 162.1 20,179.8
depletion and amortization(149.5) (230.7) (21.8) (402.0) (4,893.8) (2,027.9) (4,774.5) (11,696.2) 4,924.0 1,631.6 1,385.7 140.3 8,081.6 360.8 315.6 47.0 125.6 849.0 9,384.6 4,241.6 6,147.8 19,774.0 9,745.4 4,557.2 6,194.8 125.6 20,623.0
depletion and amortization(151.2) (233.6) (21.8) (406.6) (4,605.9) (2,877.2) (4,566.6) (12,049.7) 4,988.3 1,446.4 1,628.2 103.8 8,166.7 (Millions of dollars)United
StatesCanada Other Total December 31, 2023 Unproved oil and natural gas properties $ 337.3 $ 13.1 $ 49.7 $ 400.1 Proved oil and natural gas properties 15,868.4 4,716.0 153.7 20,738.1 Gross capitalized costs 16,205.7 4,729.1 203.4 21,138.2 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties (105.3) – (17.4) (122.7) Proved oil and natural gas properties (9,552.9) (3,233.7) (42.8) (12,829.4) Net capitalized costs $ 6,547.5 $ 1,495.4 $ 143.2 $ 8,186.1 December 31, 2022 Unproved oil and natural gas properties $ 494.6 $ 19.2 $ 135.1 $ 648.9 Proved oil and natural gas properties 15,051.9 4,684.8 55.9 19,792.6 Gross capitalized costs 15,546.5 4,704.0 191.0 20,441.5 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties (117.8) – (14.7) (132.5) Proved oil and natural gas properties (8,873.6) (3,208.0) (41.3) (12,122.9) Net capitalized costs $ 6,555.1 $ 1,496.0 $ 135.0 $ 8,186.1 Note:Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells and exploratory wells capitalized pending further evaluation.117118MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
Quarter
Quarter
Quarter
Quarter544.7 509.7 498.3 545.0 2,097.7
income taxes154.9 (21.9) (63.6) 2.4 71.8 57.5 (17.3) (66.3) (284.8) (310.9) 58.5 (17.6) (65.9) (286.8) (311.8)
Common share0.33 (0.10) (0.38) (1.65) (1.81) 0.33 (0.10) (0.38) (1.65) (1.81) 0.34 (0.10) (0.38) (1.66) (1.81) 0.34 (0.10) (0.38) (1.66) (1.81) 0.25 0.25 0.25 0.25 1.00 32.18 28.71 27.43 31.98 32.18 25.76 24.06 22.63 25.02 22.63 429.1 411.2 486.3 483.0 1,809.6
income taxes(265.0) (131.3) (16.7) (80.1) (493.1) (199.5) 2.9 (14.6) (62.8) (274.0) (198.8) 2.9 (16.2) (63.9) (276.0)
Common share(1.16) 0.02 (0.08) (0.36) (1.59) (1.16) 0.02 (0.08) (0.36) (1.59) (1.16) 0.02 (0.08) (0.37) (1.60) (1.16) 0.02 (0.08) (0.37) (1.60) 0.35 0.35 0.25 0.25 1.20 26.69 36.24 32.66 34.30 36.24 15.76 23.49 25.14 25.00 15.76 (Millions of dollars except per share amounts)First
QuarterSecond
QuarterThird
QuarterFourth
QuarterYear 1Year ended December 31, 2023 Revenue from contracts with customers $ 840.0 $ 812.9 $ 953.8 $ 842.2 $ 3,448.9 Income (loss) from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0 Income (loss) from continuing operations 214.0 92.5 278.2 140.5 725.2 Net income (loss) including noncontrolling interest 214.3 91.9 277.8 139.7 723.7 Net income (loss) attributable to Murphy 191.6 98.3 255.3 116.4 661.6 Income (loss) from continuing operations per common share ² Basic 1.23 0.63 1.64 0.76 4.27 Diluted 1.22 0.62 1.63 0.75 4.23 Net income (loss) per common share ² Basic 1.23 0.63 1.64 0.76 4.26 Diluted 1.22 0.62 1.63 0.75 4.22 Cash dividend per common share 0.275 0.275 0.275 0.275 1.100 Year ended December 31, 2022 Revenue from contracts with customers $ 871.4 $ 1,196.2 $ 1,166.4 $ 986.1 $ 4,220.1 Income (loss) from continuing operations before income taxes (81.9) 515.5 734.0 282.7 1,450.3 Income (loss) from continuing operations (64.9) 410.4 574.5 220.8 1,140.8 Net income (loss) including noncontrolling interest (65.5) 409.5 574.1 220.6 1,138.7 Net income (loss) attributable to Murphy (113.3) 350.6 528.3 199.4 965.0 Income (loss) from continuing operations per common share ² Basic (0.73) 2.27 3.40 1.28 6.23 Diluted (0.73) 2.24 3.36 1.26 6.14 Net income (loss) per common share ² Basic (0.73) 2.26 3.40 1.28 6.22 Diluted (0.73) 2.23 3.36 1.26 6.13 Cash dividend per common share 0.150 0.175 0.250 0.250 0.825 1Prices are Revenue from contracts with customers, “Income from continuing operations before income taxes”, “Income from continuing operations” and “Net income including noncontrolling interest” include results attributable to the noncontrolling interest in MP GOM.2 The sum of quarterly income (loss) from continuing operations per share and net income (loss) per share may not agree with total year net income (loss) per share as quotedeach quarterly computation is based on the New York Stock Exchange.weighted average of common shares outstanding.118119MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESSCHEDULE II –- VALUATION ACCOUNTS AND RESERVES
January 1
to Expense
December 31(Millions of dollars)Balance at
January 1Charged
to ExpenseDeductions Other Balance at December 31 2023 Deducted from asset accounts: Deducted from asset accounts: 1.6 1.6 Allowance for doubtful accounts Allowance for doubtful accounts 305.4 18.6 152.3 476.3 2022 Deducted from asset accounts: Deducted from asset accounts: 1.6 1.6 Allowance for doubtful accounts Allowance for doubtful accounts 294.4 25.7 (14.7) 305.4 2021 Deducted from asset accounts: Deducted from asset accounts: 1.6 1.6 Allowance for doubtful accounts Allowance for doubtful accounts 306.5 40.8 (52.9) 294.4 1Amounts in 2017 and 2016 for deferred tax asset valuations are primarily associated with an increase in foreign tax credit carryforwards. The amount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization120119MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIESDEFINITIONS GLOSSARYABBREVIATIONSAECO - Alberta Energy Company and is the Canadian benchmark price for natural gas3D seismicAIP - Annual Incentive PlanARO - asset retirement obligationBbl - barrelBCF - billion cubic feetBOE - barrels of oil equivalentBOEM - U.S. Bureau of Ocean Energy ManagementBOEPD - barrel of oil equivalent per dayBSEE - U.S. Bureau of Safety and Environmental EnforcementCAD orC$ - Canadian dollarCRSU - cash-settled restricted time-based stock unitDD&A - depreciation, depletion and amortizationDeepwater - offshore location in greater than 1,000 feet of waterDE&I - Diversity, Equity and InclusionDownstream - refining and marketing operationsDry hole - an exploratory well that does not find oil or natural gas in commercial quantitiesE&P - exploration and productionEBITDA - earnings before interest, taxes, depreciation and amortizationEPA - U.S. Environmental Protection AgencyExploratory well - a well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive by another reservoirFPS - floating production systemGAAP - U.S. Generally Accepted Accounting PrinciplesGHG - greenhouse gasHyrdocarbons - organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum productsLOE - lease operating expenseMCF - thousand cubic feetMMBBL - million barrels of oilMMBOE - million barrels of oil equivalentMMBTU - million British thermal unitsMMCF - million cubic feetMPGOM - MP Gulf of Mexico, LLCNCI - noncontrolling interestNet acres or net wells - the portions of gross acres or gross wells owned by the CompanyNGL - natural gas liquidNYMEX - New York Mercantile ExchangeOPEC - Organization of the Petroleum Exporting CountriesOperator - the company serving as the manager and often the decision-maker of a drilling or production projectPAI - Petrobras America Inc.PCAOB - Public Company Accounting Oversight Board121DEFINITIONS - ContinuedProduction Sharing Contract (PSC) - agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recoveredPSU - performance-based restricted stock unitQRE - qualified reserve estimatorRCF - revolving credit facilityRSU - time-based restricted stock unitSAR - stock appreciation rightSEAL - Sergipe-Alagoas BasinSEC - U.S. Securities and Exchange CommissionSeismic - two-dimensional or three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbonsARO - Asset Retirement ObligationASU - Accounting Standards Updatedeepwateroffshore location in greater than 1,000 feet of waterBCFSOFR - Billion cubic feetSecured Overnight Financing Ratedownstreamrefining and marketing operationsBOEDTCFD - Barrel of oil equivalent per dayTask Force on Climate-related Financial Disclosuresdry holean unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expenseFASBUpstream - Financial Accounting Standards BoardFLNG - Floating Liquified Natural Gasexploratorywildcat and delineation, e.g., exploratory wellsGAAP - U.S. Generally Accepted Accounting Principleshydrocarbonsorganic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum productsGK - Gumusut/KakapLTM - Last twelve monthsMCF - Thousand cubic feetproduction sharing contractagreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recoveredMMBOE - Million barrels of oil equivalentMMCF - Million cubic feetMOCL- Murphy Oil Company Ltd.synthetic oila light, sweet crude oil produced by upgrading bitumen recovered from oil sandsNYMEX - New York Mercantile ExchangeOSHA - Occupational Safety and Health Actoil sandstar-like hydrocarbon-bearing substance that occurs naturally in certain areas at the Earth’s surface or at relatively shallow depths and which can be recovered, processed and upgraded into a light, sweet synthetic crude oilQRE - Qualified Reserve EstimatorsR&M - Refining and MarketingSEC - U.S. Securities and Exchange Commissionoperatorthe company serving as the manager and often the decision-maker of a drilling or production projectUFA - Unitization Framework AgreementWCSB - Western Canadian Sedimentary Basinunitizationcombining of multiple mineral or leasehold interests to be able to produce from a common reservoirWTI - West Texas Intermediateupstreamoperationoperations workingUSD - United States dollarVIE - variable interestWorking interest - right to drill and produce oil and natural gas on the leased acreage, as well as the obligation to pay costsWTI - West Texas Intermediate122120