Murphy Oil (MUR) 10-K23 Feb 242023 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2023	Jan. 31, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-8590
Entity Registrant Name	MURPHY OIL CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	71-0361522
Entity Address, Address Line One	9805 Katy Fwy, Suite G-200
Entity Address, Postal Zip Code	77024
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
City Area Code	(281)
Local Phone Number	675-9000
Title of 12(b) Security	Common Stock, $1.00 Par Value
Trading Symbol	MUR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 4,406,165,207
Entity Common Stock, Shares Outstanding		152,755,027
Documents Incorporated by Reference	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.
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0000717423
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	185
Auditor Name	KPMG LLP
Auditor Location	Houston, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 317,074	$ 491,963
Accounts receivable, net	343,992	391,152
Inventories	54,454	54,513
Prepaid expenses	36,674	34,697
Total current assets	752,194	972,325
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $13,135,385 in 2023 and $12,489,970 in 2022	8,225,197	8,228,016
Operating lease assets	745,185	946,406
Deferred income taxes	435	117,889
Deferred charges and other assets	43,686	44,316
Total assets	9,766,697	10,308,952
Current liabilities
Current maturities of long-term debt, finance lease	723	687
Accounts payable	446,891	543,786
Income taxes payable	21,007	26,544
Other taxes payable	29,339	22,819
Operating lease liabilities	207,840	220,413
Other accrued liabilities	140,745	443,585
Total current liabilities	846,545	1,257,834
Long-term debt, including finance lease obligation	1,328,352	1,822,452
Asset retirement obligations	904,051	817,268
Deferred credits and other liabilities	309,605	304,948
Non-current operating lease liabilities	551,845	742,654
Deferred income taxes	276,646	214,903
Total liabilities	4,217,044	5,160,059
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	0	0
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2023 and 195,100,628 shares in 2022	195,101	195,101
Capital in excess of par value	880,297	893,578
Retained earnings	6,546,079	6,055,498
Accumulated other comprehensive loss	(521,117)	(534,686)
Treasury stock	(1,737,566)	(1,614,717)
Murphy Shareholders' Equity	5,362,794	4,994,774
Noncontrolling interest	186,859	154,119
Total equity	5,549,653	5,148,893
Total liabilities and equity	$ 9,766,697	$ 10,308,952

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Accumulated depreciation, depletion and amortization	$ 13,135,385	$ 12,489,970
Cumulative preferred stock, par value (in USD per share)	$ 100	$ 100
Cumulative preferred stock, authorized shares (in shares)	400,000	400,000
Cumulative preferred stock, shares issued (in shares)	0	0
Common Stock, par value (in USD per share)	$ 1	$ 1
Common stock, authorized shares (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	195,100,628	195,100,628

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues and other income
Total revenue from sales to customers	$ 3,448,854	$ 4,220,140	$ 2,801,215
(Loss) on derivative instruments	0	(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	0
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	0	0	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 (in USD per share)	$ 4.27	$ 6.23	$ (0.47)
Discontinued operations (in USD per share)	(0.01)	(0.01)	(0.01)
Net Income (loss) (in USD per share)	4.26	6.22	(0.48)
INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations (in USD per share)	4.23	6.14	(0.47)
Discontinued operations (in USD per share)	(0.01)	(0.01)	(0.01)
Net income (loss) (in USD per share)	4.22	6.13	(0.48)
Cash dividends per Common share (in USD per share)	$ 1.100	$ 0.825	$ 0.500
Average common shares outstanding (thousands)
Basic (in shares)	155,233,560	155,276,533	154,290,741
Diluted (in shares)	156,646,429	157,474,838	154,290,741
Revenue from production
Revenues and other income
Total revenue from sales to customers	$ 3,376,639	$ 4,038,451	$ 2,801,215
Sales of purchased natural gas
Revenues and other income
Total revenue from sales to customers	$ 72,215	$ 181,689	$ 0

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interest	$ 723,681	$ 1,138,719	$ 47,528
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	36,598	(106,335)	12,116
Retirement and postretirement benefit plans	(23,029)	99,360	59,816
Deferred loss on interest rate hedges reclassified to interest expense	0	0	1,690
Other comprehensive income (loss)	13,569	(6,975)	73,622
Comprehensive income including noncontrolling interest	737,250	1,131,744	121,150
Less: Comprehensive income attributable to noncontrolling interest	62,122	173,672	121,192
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$ 675,128	$ 958,072	$ (42)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 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)	0
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		0	(214,788)	112,113
Loss from discontinued operations		1,467	2,078	1,225
Gain from sale of assets		(12)	(17,899)	0
Impairment of assets		0	0	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		0	0	(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		0	(8,295)	(39,335)
Repurchase of common stock		(150,022)	0	0
Contingent consideration paid		(60,243)	(81,742)	0
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		0	0	541,913
Issue costs of debt facility		(20)	(14,353)	0
Net cash required by financing activities		(923,718)	(1,081,621)	(794,513)
Net cash required by discontinued operations		0	(14,500)	0
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

[1]Certain prior-period amounts have been reclassified to conform to the current period presentation.

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands		Total	Murphy Shareholders’ Equity	Cumulative Preferred Stock	Common Stock	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Loss	Treasury Stock	Noncontrolling Interest
Balance at beginning and end of period at Dec. 31, 2020						$ 941,692	$ 5,369,538	$ (601,333)	$ (1,690,661)	$ 179,810
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation						25,429
Stock issued during period, value, restricted stock award	[1]					(40,423)
Net income (loss) attributable to Murphy		$ (73,664)					(73,664)			121,192
Cash dividends paid							(77,204)
Foreign currency translation (losses) gains, net of income taxes		12,116						12,116
Retirement and postretirement benefit plans, net of income taxes								59,816
Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes		1,690						1,690
Purchase of treasury shares									0
Awarded restricted stock, net of forfeitures									35,214
Distributions to noncontrolling interest owners										(137,517)
Balance at end of year at Dec. 31, 2021		4,320,796	$ 4,157,311	$ 0	$ 195,101	926,698	5,218,670	(527,711)	(1,655,447)	163,485
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation						25,242
Stock issued during period, value, restricted stock award	[1]					(58,362)
Net income (loss) attributable to Murphy		965,047					965,047			173,672
Cash dividends paid							(128,219)
Foreign currency translation (losses) gains, net of income taxes		(106,335)						(106,335)
Retirement and postretirement benefit plans, net of income taxes								99,360
Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes		0						0
Purchase of treasury shares									0
Awarded restricted stock, net of forfeitures									40,730
Distributions to noncontrolling interest owners										(183,038)
Balance at end of year at Dec. 31, 2022		5,148,893	4,994,774	0	195,101	893,578	6,055,498	(534,686)	(1,614,717)	154,119
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation						29,386
Stock issued during period, value, restricted stock award	[1]					(42,667)
Net income (loss) attributable to Murphy		661,559					661,559			62,122
Cash dividends paid							(170,978)
Foreign currency translation (losses) gains, net of income taxes		36,598						36,598
Retirement and postretirement benefit plans, net of income taxes								(23,029)
Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes		0						0
Purchase of treasury shares									(151,241)
Awarded restricted stock, net of forfeitures									28,392
Distributions to noncontrolling interest owners										(29,382)
Balance at end of year at Dec. 31, 2023		$ 5,549,653	$ 5,362,794	$ 0	$ 195,101	$ 880,297	$ 6,546,079	$ (521,117)	$ (1,737,566)	$ 186,859

[1]Prior-period amounts have been aggregated to conform to the current period presentation.

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Cumulative preferred stock, par value (in USD per share)	$ 100	$ 100	$ 100
Cumulative preferred stock, authorized shares (in shares)	400,000	400,000	400,000
Cumulative preferred stock, shares issued (in shares)	0	0	0
Common Stock, par value (in USD per share)	$ 1	$ 1	$ 1
Common stock, authorized shares (in shares)	450,000,000	450,000,000	450,000,000
Common stock, shares issued (in shares)	195,100,628	195,100,628	195,100,628
Treasury stock, common shares (in shares)	42,351,986	39,633,309	40,637,578

Significant Accounting Polices

Significant Accounting Polices	12 Months Ended
Significant Accounting Polices	Dec. 31, 2023
Accounting Policies [Abstract]
Significant Accounting Polices	Note A – Significant Accounting Polices NATURE 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 and Canada and conducts oil and gas exploration activities worldwide. 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. Intercompany accounts and transactions are eliminated. USE OF ESTIMATES – Preparing the financial statements of the Company in accordance with GAAP requires management to make a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates. 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; 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 in 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 Company 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, 2023 and 2022, the liabilities for natural gas balancing were immaterial. Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues. 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 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. ACCOUNTS RECEIVABLE – At December 31, 2023 and 2022, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural 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 are 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 (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing 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. See Note E . 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 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 and equipment” 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 were no impairments recognized in 2023 and 2022. 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 ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings. See Note G for further discussion. Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production. Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition 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. 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, plant and equipment” 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 an 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 basis 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. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be 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 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 as part of interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in “Accumulated Other Comprehensive Loss” in Consolidated Statements of Stockholders’ Equity. 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 to 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 “Accumulated other comprehensive loss” 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 other comprehensive loss” is recognized immediately in earnings. 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. See Note O . STOCK-BASED COMPENSATION Equity-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 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 Cash-Settled Awards – The Company accounts for stock appreciation rights (SARs) and cash-settled restricted time-based stock units (CRSUs) as liability awards. Expense associated with these awards is 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 SARs and the period-end price of the Company’s common stock for time-based CRSUs. When SARs are exercised and when CRSUs settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note I . 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 other comprehensive loss”. The remaining amounts in “Accumulated other comprehensive loss” include net actuarial losses and prior service (cost) credit. See Note J . 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.

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2023
Accounting Changes and Error Corrections [Abstract]
New Accounting Principles and Recent Accounting Pronouncements	Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted None affecting the Company. Recent Accounting Pronouncements Income Tax Disclosures. In December 2023 the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures . The standard becomes effective for annual periods beginning after December 15, 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 fiscal years beginning after December 15, 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. The standard does not affect our determination of significant segments. Murphy is currently evaluating the impact of adopting this standard.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
Revenue from Contracts with Customers	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Note C – Revenue from Contracts with Customers Nature of Goods and Services The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids and natural gas. For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by GAAP. U.S. - In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas 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 volumes on the bill of lading and point of custody transfer. Disaggregation of Revenue The Company reviews 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 each of the three 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 1 2,072,353 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 1 47,434 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 1 71,332 161,160 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 income 11,293 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 MP GOM. In 2022, the Company included additional line items on the face of the Consolidated Statements of Operations to report “Sales of purchased natural gas” and “Costs of purchased natural gas”. Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and has risks and rewards of ownership. Sales of natural gas are reported when the contractual performance obligations are satisfied. This occurs at the time the product is delivered to a third party purchaser at the contractually determinable price. Contract Balances and Asset Recognition As 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 Company has not entered into any revenue contracts that have financing components as of December 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 the costs to obtain a contract with a customer. Performance Obligations The 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 sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract: 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 purchases for accounting purposes.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
Property, Plant and Equipment	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note D – Property, Plant and Equipment The Company’s property, plant and equipment assets for the respective periods are presented as follows: 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 $15,356 in 2023 and $18,319 in 2022 related to administrative assets and support equipment. Divestments On September 15, 2023, the Company completed the 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 effective date of the transaction was March 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 obligations of approximately $47.9 million. A $17.9 million gain on sale was recorded in the period related to the sale. In September 2022, the Company completed the disposition of the 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. Acquisitions In August 2022, the Company acquired an additional working interest of 3.37% in the Lucius field for a purchase price of $78.5 million, net of closing adjustments. In June 2022, the Company acquired an additional working interest of 11.0% in the Kodiak field for a purchase price of $50.0 million, net of closing adjustments. Impairments The following table reflects the recognized before tax impairments for each of the three years presented. (Thousands of dollars) 2023 2022 2021 Canada $ – $ – $ 171,296 Other Foreign – – 18,000 Corporate – – 7,000 $ – $ – $ 196,296 Exploratory Wells Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well, and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. At December 31, 2023, 2022 and 2021, the Company had total capitalized drilling costs pending the determination of proved reserves of $49.1 million, $171.9 million and $179.5 million, respectively. The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented. ( 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 Reclassifications to proved properties of $82.2 million, for the year ended December 31, 2023, are primarily related to LDV-4X in Vietnam. Capitalized well costs charged to dry hole expense of $40.6 million are related to the Cholula-1EXP well in offshore Mexico, and Oso #1 (Atwater Valley 138), and Chinook #7 (Walker Ridge 425) exploration wells in the Gulf of Mexico. The preceding table excludes well costs of $129.2 million incurred and expensed directly to dry 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. The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project. 2023 2022 2021 ( Thousands of dollars ) Amount No. of No. of Amount No. of No. of Amount No. of No. of Aging of capitalized well costs Zero to one year $ – – – $ 15,527 2 2 $ 13,273 3 3 One to two years – – – 13,307 2 2 – – – Two to three years 2,698 1 1 – – – 53,070 5 5 Three years or more 46,420 3 3 143,026 5 4 113,138 6 – $ 49,118 4 4 $ 171,860 9 8 $ 179,481 14 8 Of the $49.1 million of exploratory well costs capitalized more than one year at December 31, 2023, $26.5 million is in the U.S., $15.1 million is in Vietnam, $4.8 million is in 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.

Inventories

Inventories	12 Months Ended
Inventories	Dec. 31, 2023
Inventory Disclosure [Abstract]
Inventories	Note E – Inventories Inventories 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

Financing Arrangements and Debt

Financing Arrangements and Debt	12 Months Ended
Financing Arrangements and Debt	Dec. 31, 2023
Debt Disclosure [Abstract]
Financing Arrangements and Debt	Note F – Financing Arrangements and Debt Long-term debt for the respective periods presented consisted of the following: 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 1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s. The amounts of long-term debt repayable over each of the next five years and thereafter are as follows: nil in 2024, nil in 2025, nil in 2026, $443.2 million in 2027, $372.2 million in 2028 and $519.5 million thereafter. The Company also has a shelf registration statement on file with the SEC that permits the offer and sale of debt and/or equity securities through October 15, 2024. 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 recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the RCF. At December 31, 2023, the Company had no outstanding borrowings under the RCF 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 the RCF. In November 2023, the Company tendered a total of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $250 million in aggregate principal. The cost of debt extinguishment of $1.3 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023. There were no additional cash costs related to the November 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 tendered $100.0 million and $98.1 million aggregate principal amount of its 2025 Notes and 2028 Notes, respectively. The total cost of the debt extinguishment of $4.0 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022. The debt extinguishment on the 2025 and 2028 Notes had cash costs of $2.0 million and is shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note G – Asset Retirement Obligations The asset retirement obligations liabilities recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment. A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the respective periods presented is shown in the following table. (Thousands of dollars) 2023 2022 Balance at beginning of year $ 911,653 $ 971,893 Accretion 46,059 46,243 Liabilities incurred 20,628 46,449 Revisions of previous estimates 29,056 (78,229) Liabilities settled (95,637) (64,255) Changes due to translation of foreign currencies 3,004 (10,448) Balance at end of year 914,763 911,653 Current portion of liability ¹ (10,712) (94,385) Noncurrent portion of liability $ 904,051 $ 817,268 1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets. The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Note H – Income Taxes The 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 Income (loss) from continuing operations before income taxes United States $ 901,761 $ 1,306,200 $ 114,659 Foreign 19,308 144,061 (71,768) Total $ 921,069 $ 1,450,261 $ 42,891 Income tax expense (benefit) U.S. Federal – Current $ – $ – $ – – Deferred 170,115 234,749 (1,480) Total U.S. Federal 170,115 234,749 (1,480) State 6,622 9,010 3,303 Foreign – Current 13,182 18,134 (5,158) – Deferred 6,002 47,571 (2,527) Total Foreign 19,184 65,705 (7,685) Total $ 195,921 $ 309,464 $ (5,862) The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense for each of the three 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) An analysis of the Company’s deferred tax assets and deferred tax liabilities for the respective periods presented showing the tax effects of significant temporary differences follows. ( Thousands of dollars ) 2023 2022 Deferred tax assets Property and leasehold costs $ 240,065 $ 242,467 Liabilities for dismantlements 34,258 31,017 Postretirement and other employee benefits 82,437 86,798 U. S. net operating loss 357,490 442,699 Investment in partnership 14,655 11,595 Other deferred tax assets 48,778 111,212 Total gross deferred tax assets 777,683 925,788 Less valuation allowance (146,861) (136,008) Net deferred tax assets 630,822 789,780 Deferred tax liabilities Deferred tax on undistributed foreign earnings (5,000) (5,000) Accumulated depreciation, depletion and amortization (847,981) (796,510) Other deferred tax liabilities (54,052) (85,284) Total gross deferred tax liabilities (907,033) (886,794) Net deferred tax (liabilities) assets $ (276,211) $ (97,014) 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 for deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions that in the judgment of management at the present time are more likely than not to be unrealized. The valuation allowance increased $10.9 million in 2023, related all to 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 a U.S. net operating loss carryforward of $1.7 billion at year-end 2023 with a corresponding deferred tax asset of $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 expirations in 2036 and 2037. Other Information Currently, the Company considers $100 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $5 million liability. At December 31, 2023, $1.5 billion of past foreign earnings are considered permanently reinvested. The Company closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to our business and the future operation of the Company. Uncertain Income Tax Positions 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 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 “Other taxes payable” and “Deferred credits and other liabilities” in the Consolidated Balance 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. ( 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, 2023, 2022 and 2021, respectively, for interest and penalties associated with uncertain tax positions. There were no interest or penalties associated with uncertain tax positions included in income tax expense for any period presented. In 2024, the Company currently does not expect to add to the provision for uncertain tax positions. Although existing liabilities could be reduced by settlement with taxing authorities or 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 2024. 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, 2023, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; and Malaysia – 2017. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

Incentive Plans

Incentive Plans	12 Months Ended
Incentive Plans	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Incentive Plans	Note I – Incentive Plans Murphy utilizes cash-based and/or share-based incentive awards 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 cash-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. The 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 2020 Long-Term Incentive Plan (2020 Long-Term Plan). The AIP authorizes the 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 AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2020 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock to employees. These grants may be in the form of stock options (nonqualified or incentive), SARs, restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5 million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan. Based on awards made to date, 2.1 million shares are available for grant under the 2020 Long-Term Plan at December 31, 2023. The Stock Plan for Non-Employee Directors (2021 NED Plan) permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company 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. ( Thousands of dollars ) 2023 2022 2021 Compensation charged against income before income tax benefit $ 58,760 $ 74,587 $ 43,660 Related income tax benefit recognized in income 9,330 12,710 7,196 As of December 31, 2023, there were $47.4 million in compensation costs, to be expensed over approximately the next three years, related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable withholding obligations, upon each stock option exercise and restricted stock unit vest. Equity-Settled Awards PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2020 under the 2018 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, PSUs will not vest, but the recognized compensation cost associated with the stock award would not be reversed. For PSUs, the performance conditions are based on the Company’s total shareholder return (80% weighting), compared to an industry peer group of companies, and the EBITDA divided by Average Capital Employed metric (20% weighting) for PSU awards, over the performance period. During the performance period, PSUs 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 nor do voting rights exist on awards of PSUs prior to their settlement. Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2023 2022 2021 Outstanding at beginning of year 2,148,467 2,670,756 2,207,429 Granted 409,160 595,700 1,156,800 Vested and issued (408,135) (654,177) (642,473) Forfeited (331,304) (463,812) (51,000) Outstanding at end of year 1,818,188 2,148,467 2,670,756 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 2023, 2022 and 2021 are presented in the following table. 2023 2022 2021 Fair value per share at grant date $60.46 $37.77 - $47.37 $16.03 Assumptions 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-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s Non-Employee Directors (NED) under the 2018 NED Plan and 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan. The 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 1 Closing Stock Price at Grant Date $43.27 $32.84 $13.14 - $23.58 Long-Term Incentive Plan 2 Average 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. Changes in RSUs outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2023 2022 2021 Outstanding at beginning of year 1,227,792 1,451,438 1,383,043 Granted 556,100 416,492 573,907 Vested and issued (517,047) (462,418) (476,012) Forfeited (47,261) (177,720) (29,500) Outstanding at end of year 1,219,584 1,227,792 1,451,438 STOCK 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 fair value of each option award was 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. Number of Average Outstanding 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 Awards The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of SARs and CRSUs. SAR awards have terms similar to stock options. CRSUs generally settle on the third anniversary of the date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with common shares. Total pre-tax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $29.4 million in 2023, $49.3 million in 2022 and $18.2 million in 2021. 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 $30.9 million, $42.9 million and $29.0 million was recorded in 2023, 2022 and 2021, respectively, for these plans.

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans	12 Months Ended
Employee and Retiree Benefit Plans	Dec. 31, 2023
Retirement Benefits [Abstract]
Employee and Retiree Benefit Plans	Note J – Employee and Retiree Benefit Plans PENSION 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. 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 Sheets and to recognize changes in that funded status between periods through “Accumulated other comprehensive loss”. The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status for the respective periods presented. Pension Other ( Thousands of dollars ) 2023 2022 2023 2022 Change in benefit obligation Obligation at January 1 $ 663,073 $ 939,380 $ 67,679 $ 96,133 Service cost 6,542 7,875 495 968 Interest cost 34,140 22,747 3,241 2,211 Participant contributions – – 2,629 2,283 Actuarial loss (gain) 26,625 (238,407) (5,567) (29,533) Medicare Part D subsidy – – 299 331 Exchange rate changes 6,089 (21,018) 2 (20) Benefits paid (56,296) (47,504) (4,970) (4,694) Plan amendments 1 18,978 – – – Obligation at December 31 699,151 663,073 63,808 67,679 Change in plan assets Fair value of plan assets at January 1 450,944 611,302 – – Actual return on plan assets 39,953 (133,395) – – Employer contributions 37,546 41,145 2,042 2,080 Participant contributions – – 2,629 2,283 Medicare Part D subsidy – – 299 331 Exchange rate changes 5,662 (20,604) – – Benefits paid (56,296) (47,504) (4,970) (4,694) Fair value of plan assets at December 31 477,809 450,944 – – Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 3,192 3,584 – – Other accrued liabilities (10,219) (9,693) (4,433) (4,830) Deferred credits and other liabilities (214,315) (206,020) (59,375) (62,849) Fund Status and net plan liability recognized at December 31 $ (221,342) $ (212,129) $ (63,808) $ (67,679) 1 At December 31, 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 other comprehensive loss” (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table. ( Thousands of dollars ) Pension Other Net actuarial gain (loss) $ (202,868) $ 44,165 Prior service (credit) cost (20,561) 3,937 $ (223,429) $ 48,102 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 ) 2023 2022 2023 2022 2023 2022 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 534,751 $ 511,375 $ 523,096 $ 499,338 $ 461,363 $ 434,283 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 151,146 141,917 148,661 139,634 – – Unfunded other postretirement plans 63,808 67,679 63,808 67,679 – – The table that follows provides the components of net periodic benefit expense for each of the three years presented. Pension Benefits Other ( Thousands of dollars ) 2023 2022 2021 2023 2022 2021 Service cost $ 6,542 $ 7,875 $ 8,199 $ 495 $ 968 $ 1,295 Interest cost 34,140 22,747 14,784 3,241 2,211 2,071 Expected return on plan assets (32,839) (36,458) (19,222) – – – Amortization of prior service cost (credit) 620 (684) 591 (532) (532) – Recognized actuarial (gain) loss 9,776 16,098 20,565 (3,512) (615) (29) Net periodic benefit expense 18,239 9,578 24,917 (308) 2,032 3,337 Curtailment expense 219 – – – – – Total net periodic benefit expense $ 18,458 $ 9,578 $ 24,917 $ (308) $ 2,032 $ 3,337 The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Other ( Thousands of dollars ) 2023 2022 2023 2022 Benefit obligation at December 31 $ 133,822 $ 122,915 $ 115 $ 107 Fair value of plan assets at December 31 119,236 115,862 – – Net plan liabilities recognized (14,586) (7,053) (115) (107) Net periodic benefit expense (benefit) 1,387 (5,322) (44) 62 The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2023 and 2022 and net periodic benefit expense for 2023 and 2022. Benefit Obligations Net Periodic Benefit Expense Pension Other Pension Other December 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 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. The plan’s cash balance interest accumulation rate is the greater of the annual yield on 10-year treasury constant maturities or 1.89%. 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 Other 2024 $ 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 For purposes of measuring postretirement benefit obligations at December 31, 2023, the future annual rates of increase in the cost of health care were assumed to be 7.4% for 2024 decreasing each year to an ultimate rate of 4.0% in 2048 and thereafter. During 2023, the Company made contributions of $34.7 million to its domestic defined benefit pension plans and $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 $4.4 million to its domestic postretirement benefits plan. PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. Our investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and includes equities, fixed income and other investments, including hedge funds, real estate and cash equivalent securities. Investment managers are prohibited from investing in equity or fixed income securities issued by the Company. The majority of plan assets are highly liquid, providing flexibility for benefit payment requirements. The current target allocations for plan assets are 40-75% equity securities, 20-60% fixed income securities, 0-15% alternatives and 0-20% cash and equivalents. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels. The weighted average asset allocation for the Company’s funded pension benefit plans at the respective balance sheet dates are shown 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 % The Company’s weighted average expected return on plan assets was 7.4% in 2023 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 7.4% expected return was comprised of the weighted average expected future equity securities return of 8.4% and a fixed income securities return of 4.7%. An average expected investment expense of 0.8% is included in this calculation. Over the last 10 years, the return on funded retirement plan assets has averaged 3.0%. At December 31, 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, Quoted Prices Significant Significant 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 At December 31, 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, Quoted Prices Significant Significant 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 The definition of levels within the fair value hierarchy in the tables above is included in Note O . For domestic plans, U.S. core, small/midcap, international, emerging market equity securities and U.S. treasury securities are valued based on quoted prices in active markets. For commercial paper securities, the prices received generally utilize observable inputs in the pricing methodologies. Other alternative strategies funds consist of two investments. One of these investments is valued annually based on net asset value and permits withdrawals annually after a 90-day notice, and the other investment is also valued quarterly based on net asset values and has a three-year lock-up period and a 95-day notice following the lock-up period. 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 U.K. and foreign equity securities. The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: ( Thousands of dollars ) Hedged Funds and Other Total at December 31, 2021 $ 82,854 Actual return on plan assets: Relating to assets held at the reporting date (38,389) Purchases, sales and settlements (11,731) Total at December 31, 2022 32,734 Actual return on plan assets: Relating to assets held at the reporting date 711 Relating to assets sold during the period (8,991) Total at December 31, 2023 $ 24,454 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 6.0%. Amounts charged to expense for the Company’s match to these plans were $8.5 million in 2023, $6.0 million in 2022 and $5.4 million in 2021.

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
Financial Instruments and Risk Management	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Financial Instruments and Risk Management	Note K – Financial Instruments and Risk Management DERIVATIVE INSTRUMENTS – Murphy 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 with creditworthy major financial institutions or over national exchanges such as the New York Mercantile 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 and amortized to “Interest expense, net” over time. In 2021, the 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. Commodity Price Risks During 2022, the Company had crude oil swaps and collar contracts. Under the swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract 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. At December 31, 2023 and December 31, 2022, the Company did not have any outstanding crude oil derivative contracts. At December 31, 2021, the Company had 20,000 barrels per day in NYMEX WTI swap contracts at a price per barrel of $44.88 and 25,000 barrels per day in NYMEX WTI collar 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 2022. Foreign Currency Exchange Risks The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2023 and 2022. The gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments for each of the three years presented are shown in the following table. Gain (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) Credit 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 cost sharing amounts, of operating and capital costs billed to partners, for properties operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended. 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 associated with any one customer. Cash balances and cash equivalents are held with several major financial institutions, which limit the Company’s exposure to credit 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.

Earnings Per Share

Earnings Per Share	12 Months Ended
Earnings Per Share	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Note L – Earnings Per Share Net income (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for each of the three years presented . The following table reconciles the weighted-average shares outstanding used for these computations. ( Weighted-average shares ) 2023 2022 2021 Basic method 155,233,560 155,276,533 154,290,741 Dilutive stock options and restricted stock units ¹ 1,412,869 2,198,305 – Diluted method 156,646,429 157,474,838 154,290,741 1 Due to a net loss recognized by the Company for the year ended December 31, 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 presented but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive. 2023 2022 2021 Antidilutive stock options excluded from diluted shares – 126,000 1,420,992 Weighted average price of these options – $49.65 $35.30

Other Financial Information

Other Financial Information	12 Months Ended
Other Financial Information	Dec. 31, 2023
Other Financial Information [Abstract]
Other Financial Information	Note M – Other Financial Information GAIN 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 $10.8 million loss in 2023, $23.0 million gain in 2022 and $1.0 million gain in 2021. Noncash operating working capital (increased) decreased during each of the three years presented as shown in the following table. ( 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 1 Excludes receivable/payable balances relating to mark-to-market of crude contracts.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	12 Months Ended
Accumulated Other Comprehensive Loss	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Loss	Note N – Accumulated Other Comprehensive Loss The components of AOCL on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table. ( Thousands of dollars ) Foreign Retirement and 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 $5.6 million and $15.3 million are included in the computation of net periodic benefit expense in 2023 and 2022, respectively. See Note J for additional information. Related income taxes of $1.1 million and $3.3 million are included in income tax expense in 2023 and 2022, respectively.

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value	12 Months Ended
Assets and Liabilities Measured at Fair Value	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Note O – Assets and Liabilities Measured at Fair Value Fair Values – Recurring The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. The fair value measurements for these assets and liabilities for the respective periods presented are shown in the following table. 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 nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations. 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, 2023 and 2022. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2023 and 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 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 value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal. December 31, 2023 2022 ( Thousands of dollars ) Carrying Fair Carrying Fair Financial liabilities: Current and long-term debt $ 1,329,075 $ 1,265,185 $ 1,823,139 $ 1,668,216 Fair Values – Nonrecurring

Commitments

Commitments	12 Months Ended
Commitments	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments	Note P – Commitments The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Canada Onshore. The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2045, while the Canada Onshore processing contracts call for minimum monthly payments through 2051. In the U.S. and Canada Onshore, future required minimum annual payments for the next five years are $225.9 million in 2024, $126.0 million in 2025, $114.7 million in 2026, $103.5 million in 2027 and $94.4 million in 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 $295.1 million in 2023, $216.4 million in 2022 and $151.8 million in 2021. Commitments for capital expenditures were approximately $209.8 million at December 31, 2023, including $173.3 million for costs to develop deepwater U.S. Gulf of Mexico fields, $13.3 million for Eagle Ford Shale, $19.2 million for Canada and $4.0 million for Other Foreign.

Environmental and Other Conting

Environmental and Other Contingencies	12 Months Ended
Environmental and Other Contingencies	Dec. 31, 2023
Environmental Remediation Obligations [Abstract]
Environmental and Other Contingencies	Note Q – Environmental and Other Contingencies The 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 government action intended for the promotion of safety and the protection and/or remediation of the 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. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they 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 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. 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. There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, 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, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (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. 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. There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be 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.

Common Stock Issued and Outstan

Common Stock Issued and Outstanding	12 Months Ended
Common Stock Issued and Outstanding	Dec. 31, 2023
Equity [Abstract]
Common Stock Issued and Outstanding	Note R – Common Stock Issued and Outstanding Activity in the number of shares of common stock issued and outstanding for each of the three years presented is shown below. ( Number of shares outstanding ) 2023 2022 2021 Beginning of year 155,467,319 154,463,050 153,598,625 Stock options exercised 1 2,657 181,655 32,554 Restricted stock awards 1 689,824 822,614 831,871 Treasury shares purchased (3,411,158) – – End of year 152,748,642 155,467,319 154,463,050 1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note I 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.

Business Segments

Business Segments	12 Months Ended
Business Segments	Dec. 31, 2023
Segment Reporting [Abstract]
Business Segments	Note S – Business Segments Murphy’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 and all other countries. Each of these segments derive 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. Customers that accounted for 10% or more of the Company’s sales 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 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. No assets were held for sale as of December 31, 2023 and 2022. The former U.K. and U.S. downstream units have been reported as discontinued 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, other gains and losses (including foreign exchange gains/losses and 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. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate Discontinued Consolidated Year 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) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate Discontinued Consolidated Income 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 a noncontrolling interest in MP GOM. Geographic Information Certain long-lived assets at December 31 1 ( Millions of dollars ) United Canada 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, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2023
Leases [Abstract]
Leases	Note T – Leases Nature of Leases The 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 year 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 Expenses Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows: Year Ended December 31, (Thousands of dollars) Financial Statement Category 2023 2022 Operating lease 1, 2 Lease operating expenses $ 246,721 $ 217,038 Operating lease 2 Transportation, gathering and processing 37,797 39,669 Operating lease 2 Selling and general expense 9,859 8,003 Operating lease 2 Other operating expense 675 510 Operating lease 2 Exploration expenses 110,577 10,019 Operating lease 2 Property, plant and equipment 204,595 196,829 Operating lease 2 Asset 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 1 Variable lease expenses. For the years ended December 31, 2023 and 2022, 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. 2 Short-term leases due within 12 months. For the year ended December 31, 2023, includes $78.2 million in LOE, $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. Maturity 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 Rate December 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 Information Year 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.
Leases	Note T – Leases Nature of Leases The 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 year 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 Expenses Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows: Year Ended December 31, (Thousands of dollars) Financial Statement Category 2023 2022 Operating lease 1, 2 Lease operating expenses $ 246,721 $ 217,038 Operating lease 2 Transportation, gathering and processing 37,797 39,669 Operating lease 2 Selling and general expense 9,859 8,003 Operating lease 2 Other operating expense 675 510 Operating lease 2 Exploration expenses 110,577 10,019 Operating lease 2 Property, plant and equipment 204,595 196,829 Operating lease 2 Asset 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 1 Variable lease expenses. For the years ended December 31, 2023 and 2022, 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. 2 Short-term leases due within 12 months. For the year ended December 31, 2023, includes $78.2 million in LOE, $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. Maturity 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 Rate December 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 Information Year 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.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited)	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Information	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 RESERVES SCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL RESERVES SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES Reserves of crude 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” of economic 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 common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-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. 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, natural gas liquid 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. SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVES GAAP 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. 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 7 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, 2023. Equivalents ( Millions of barrels of oil equivalent ) Total United Canada 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 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. 2 Includes proved developed reserves of 12.8 MMBOE, consisting of 11.7 MMBBL oil, 0.5 MMBBL NGLs and 3.8 BCF natural gas attributable to the noncontrolling interest in MP GOM. 3 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. 2023 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney. Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney, the Eagle Ford Shale in the U.S., 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 Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive well performance in the U.S. Gulf of Mexico. Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney and Kaybob Duvernay as well as in the U.S. at the Gulf of Mexico and 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 Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive revisions in the U.S. from higher commodity prices, which partially reversed the 2020 capital expenditure reduction and improved well performance in the U.S. Gulf of Mexico. Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as 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 in the U.S. Gulf of Mexico. ( Millions of barrels ) Total United Canada 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 United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 11.7 MMBBL for Total and United 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 noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. 2023 Comments for Proved Crude Oil Reserves Changes Revisions 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 Changes Revisions 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 Changes ( Millions of barrels ) Total United Canada 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. 2023 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The negative NGL reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale. These revisions were partially offset by improvements in the U.S. Gulf of Mexico. Extensions and discoveries - In 2023, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. at the Eagle Ford Shale. 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 Natural Gas Liquids Reserves Changes Revisions of previous estimates - The positive NGL reserves revisions in 2022 resulted predominantly from improved well performance in the U.S. Gulf of Mexico and the Eagle Ford Shale, as well as in Canada at Kaybob Duvernay. Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. Gulf of Mexico and the Eagle Ford Shale, as well as in Canada at Tupper Montney and Kaybob Duvernay. 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 Natural Gas Liquids Reserves Changes ( Billions of cubic feet ) Total United Canada 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 1,4 2,556.2 293.1 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 2,4 1,279.3 212.4 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. 2023 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive 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 at Tupper Montney. Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney. 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 Natural Gas Reserves Changes Revisions 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 for drilling and expansion activities predominantly in Canada at Tupper Montney, as well as in the U.S. Gulf of Mexico and 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 Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices at Tupper Montney. Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney, as well as 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 at Terra Nova offshore Canada and in the U.S. Gulf of Mexico. ( Millions of dollars ) United Canada 1 Other 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 ( Millions of dollars ) United Canada 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 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. ( Millions of dollars ) United Canada 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 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. ( Millions of dollars ) United Canada Other Total December 31, 2023 Future cash inflows $ 18,927.6 $ 8,012.7 $ 1,004.2 $ 27,944.5 Future development costs (1,685.3) (769.6) (304.3) (2,759.2) Future production costs (7,856.2) (4,223.6) (288.7) (12,368.5) Future income taxes (1,057.5) (634.6) (121.3) (1,813.4) Future net cash flows 8,328.6 2,384.9 289.9 11,003.4 10% annual discount for estimated timing of cash flows (2,840.6) (1,056.9) (252.5) (4,150.0) Standardized measure of discounted future net cash flows $ 5,488.0 $ 1,328.0 $ 37.4 $ 6,853.4 December 31, 2022 Future cash inflows $ 27,277.9 $ 12,360.2 $ 59.2 $ 39,697.3 Future development costs (1,594.5) (642.4) (1.4) (2,238.3) Future production costs (8,297.4) (4,199.0) (12.1) (12,508.5) Future income taxes (2,606.8) (1,788.7) (5.4) (4,400.9) Future net cash flows 14,779.2 5,730.1 40.3 20,549.6 10% annual discount for estimated timing of cash flows (5,709.8) (3,015.6) (11.0) (8,736.4) Standardized measure of discounted future net cash flows $ 9,069.4 $ 2,714.5 $ 29.3 $ 11,813.2 December 31, 2021 Future cash inflows $ 18,449.1 $ 7,203.5 $ 44.0 $ 25,696.7 Future development costs (1,164.3) (521.1) (1.5) (1,686.8) Future production costs (7,140.6) (3,525.8) (9.1) (10,675.4) Future income taxes (1,024.4) (565.4) (3.0) (1,592.8) Future net cash flows 9,119.9 2,591.3 30.4 11,741.6 10% annual discount for estimated timing of cash flows (3,264.9) (1,169.3) (8.5) (4,442.7) Standardized measure of discounted future net cash flows $ 5,855.1 $ 1,422.0 $ 21.9 $ 7,299.0 1 Includes noncontrolling interest in MP GOM. 2 Totals within the table may not add as a result of rounding. The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. ( 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). ( Millions of dollars ) United Canada 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.

Supplemental Quarterly Informat

Supplemental Quarterly Information (Unaudited)	12 Months Ended
Supplemental Quarterly Information (Unaudited)	Dec. 31, 2023
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Information (Unaudited)	( Millions of dollars except per share amounts ) First Second Third Fourth Year 1 Year 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 1 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 each quarterly computation is based on the weighted average of common shares outstanding.

Schedule II - Valuation Account

Schedule II - Valuation Accounts and Reserves	12 Months Ended
Schedule II - Valuation Accounts and Reserves	Dec. 31, 2023
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation Accounts and Reserves	( Millions of dollars ) Balance at Charged Deductions Other Balance at December 31 2023 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ – $ – $ – $ 1.6 Deferred tax asset valuation allowance 136.0 10.9 – – 146.9 2022 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ – $ – $ – $ 1.6 Deferred tax asset valuation allowance 111.2 24.8 – – 136.0 2021 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ – $ – $ – $ 1.6 Deferred tax asset valuation allowance 106.4 4.8 – – 111.2

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Thousands	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss)	$ 116,400	$ 255,300	$ 98,300	$ 191,600	$ 199,400	$ 528,300	$ 350,600	$ (113,300)	$ 661,559	$ 965,047	$ (73,664)

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Significant Accounting Polices

Significant Accounting Polices (Policies)	12 Months Ended
Significant Accounting Polices (Policies)	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of presentation	BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of the Company and are presented in conformity with GAAP.
Principles of Consolidation	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. Intercompany accounts and transactions are eliminated.
Use of Estimates	USE OF ESTIMATES – Preparing the financial statements of the Company in accordance with GAAP requires management to make a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Revenue Recognition	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; 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 in 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 Company 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, 2023 and 2022, the liabilities for natural gas balancing were immaterial. Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues.
Cash Equivalents	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	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 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.
Accounts Receivable	ACCOUNTS RECEIVABLE – At December 31, 2023 and 2022, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural 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 are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.
Inventories	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 (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing 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	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 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 and equipment” 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.
Capitalized Interest	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, plant and equipment” 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	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 an 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	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	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 basis 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. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.
Foreign Currency	FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and 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 as part of interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in “Accumulated Other Comprehensive Loss” in Consolidated Statements of Stockholders’ Equity.
Derivative Instruments and Hedging Activities	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 to 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 “Accumulated other comprehensive loss” 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 other comprehensive loss” is recognized immediately in earnings. 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	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 Compensation	STOCK-BASED COMPENSATION Equity-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 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
Pension and Other Postretirement Benefit Plans	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 other comprehensive loss”. The remaining amounts in “Accumulated other comprehensive loss” include net actuarial losses and prior service (cost) credit.
Net Income (Loss) Per Common Share	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
Accounting Principles Adopted and Recent Accounting Pronouncements	Accounting Principles Adopted None affecting the Company. Recent Accounting Pronouncements Income Tax Disclosures. In December 2023 the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures . The standard becomes effective for annual periods beginning after December 15, 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 fiscal years beginning after December 15, 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. The standard does not affect our determination of significant segments. Murphy is currently evaluating the impact of adopting this standard.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
Revenue from Contracts with Customers (Tables)	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The Company’s revenues and other income for each of the three 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 1 2,072,353 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 1 47,434 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 1 71,332 161,160 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 income 11,293 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 MP GOM.
Schedule of Current Long-Term Contracts Outstanding	As of December 31, 2023, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract: 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

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The Company’s property, plant and equipment assets for the respective periods are presented as follows: 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 $15,356 in 2023 and $18,319 in 2022 related to administrative assets and support equipment.
Schedule of Recognized Impairments	The following table reflects the recognized before tax impairments for each of the three years presented. (Thousands of dollars) 2023 2022 2021 Canada $ – $ – $ 171,296 Other Foreign – – 18,000 Corporate – – 7,000 $ – $ – $ 196,296
Schedule of Net Changes in Capitalized Exploratory Well Costs	The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented. ( 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
Schedule of Aging of Capitalized Exploratory Well Costs	The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project. 2023 2022 2021 ( Thousands of dollars ) Amount No. of No. of Amount No. of No. of Amount No. of No. of Aging of capitalized well costs Zero to one year $ – – – $ 15,527 2 2 $ 13,273 3 3 One to two years – – – 13,307 2 2 – – – Two to three years 2,698 1 1 – – – 53,070 5 5 Three years or more 46,420 3 3 143,026 5 4 113,138 6 – $ 49,118 4 4 $ 171,860 9 8 $ 179,481 14 8

Inventories (Tables)

Inventories (Tables)	12 Months Ended
Inventories (Tables)	Dec. 31, 2023
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventories 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

Financing Arrangements and De_2

Financing Arrangements and Debt (Tables)	12 Months Ended
Financing Arrangements and Debt (Tables)	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt for the respective periods presented consisted of the following: 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 1

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations	A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the respective periods presented is shown in the following table. (Thousands of dollars) 2023 2022 Balance at beginning of year $ 911,653 $ 971,893 Accretion 46,059 46,243 Liabilities incurred 20,628 46,449 Revisions of previous estimates 29,056 (78,229) Liabilities settled (95,637) (64,255) Changes due to translation of foreign currencies 3,004 (10,448) Balance at end of year 914,763 911,653 Current portion of liability ¹ (10,712) (94,385) Noncurrent portion of liability $ 904,051 $ 817,268 1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The 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 Income (loss) from continuing operations before income taxes United States $ 901,761 $ 1,306,200 $ 114,659 Foreign 19,308 144,061 (71,768) Total $ 921,069 $ 1,450,261 $ 42,891 Income tax expense (benefit) U.S. Federal – Current $ – $ – $ – – Deferred 170,115 234,749 (1,480) Total U.S. Federal 170,115 234,749 (1,480) State 6,622 9,010 3,303 Foreign – Current 13,182 18,134 (5,158) – Deferred 6,002 47,571 (2,527) Total Foreign 19,184 65,705 (7,685) Total $ 195,921 $ 309,464 $ (5,862)
Schedule of Effective Income Tax Rates	The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense for each of the three 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)
Schedule of Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences	An analysis of the Company’s deferred tax assets and deferred tax liabilities for the respective periods presented showing the tax effects of significant temporary differences follows. ( Thousands of dollars ) 2023 2022 Deferred tax assets Property and leasehold costs $ 240,065 $ 242,467 Liabilities for dismantlements 34,258 31,017 Postretirement and other employee benefits 82,437 86,798 U. S. net operating loss 357,490 442,699 Investment in partnership 14,655 11,595 Other deferred tax assets 48,778 111,212 Total gross deferred tax assets 777,683 925,788 Less valuation allowance (146,861) (136,008) Net deferred tax assets 630,822 789,780 Deferred tax liabilities Deferred tax on undistributed foreign earnings (5,000) (5,000) Accumulated depreciation, depletion and amortization (847,981) (796,510) Other deferred tax liabilities (54,052) (85,284) Total gross deferred tax liabilities (907,033) (886,794) Net deferred tax (liabilities) assets $ (276,211) $ (97,014)
Schedule of Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits	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. ( 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

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
Incentive Plans (Tables)	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Share-Based Plans, Amounts Recognized in the Financial Statements	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. ( Thousands of dollars ) 2023 2022 2021 Compensation charged against income before income tax benefit $ 58,760 $ 74,587 $ 43,660 Related income tax benefit recognized in income 9,330 12,710 7,196
Schedule of Changes in PSUs and RSUs Outstanding	Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2023 2022 2021 Outstanding at beginning of year 2,148,467 2,670,756 2,207,429 Granted 409,160 595,700 1,156,800 Vested and issued (408,135) (654,177) (642,473) Forfeited (331,304) (463,812) (51,000) Outstanding at end of year 1,818,188 2,148,467 2,670,756 Changes in RSUs outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2023 2022 2021 Outstanding at beginning of year 1,227,792 1,451,438 1,383,043 Granted 556,100 416,492 573,907 Vested and issued (517,047) (462,418) (476,012) Forfeited (47,261) (177,720) (29,500) Outstanding at end of year 1,219,584 1,227,792 1,451,438
Schedule of Assumptions used in Valuation of Performance Awards Granted	The assumptions used in the valuation of the performance awards granted in 2023, 2022 and 2021 are presented in the following table. 2023 2022 2021 Fair value per share at grant date $60.46 $37.77 - $47.37 $16.03 Assumptions 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
Schedule of Stock Unit Awards	The 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 1 Closing Stock Price at Grant Date $43.27 $32.84 $13.14 - $23.58 Long-Term Incentive Plan 2 Average 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.
Schedule of Changes in Stock Options Outstanding	Changes in stock options outstanding during the last three years are presented in the following table. Number of Average Outstanding 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 – –

Employee and Retiree Benefit _2

Employee and Retiree Benefit Plans (Tables)	12 Months Ended
Employee and Retiree Benefit Plans (Tables)	Dec. 31, 2023
Retirement Benefits [Abstract]
Schedule of Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status	The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status for the respective periods presented. Pension Other ( Thousands of dollars ) 2023 2022 2023 2022 Change in benefit obligation Obligation at January 1 $ 663,073 $ 939,380 $ 67,679 $ 96,133 Service cost 6,542 7,875 495 968 Interest cost 34,140 22,747 3,241 2,211 Participant contributions – – 2,629 2,283 Actuarial loss (gain) 26,625 (238,407) (5,567) (29,533) Medicare Part D subsidy – – 299 331 Exchange rate changes 6,089 (21,018) 2 (20) Benefits paid (56,296) (47,504) (4,970) (4,694) Plan amendments 1 18,978 – – – Obligation at December 31 699,151 663,073 63,808 67,679 Change in plan assets Fair value of plan assets at January 1 450,944 611,302 – – Actual return on plan assets 39,953 (133,395) – – Employer contributions 37,546 41,145 2,042 2,080 Participant contributions – – 2,629 2,283 Medicare Part D subsidy – – 299 331 Exchange rate changes 5,662 (20,604) – – Benefits paid (56,296) (47,504) (4,970) (4,694) Fair value of plan assets at December 31 477,809 450,944 – – Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 3,192 3,584 – – Other accrued liabilities (10,219) (9,693) (4,433) (4,830) Deferred credits and other liabilities (214,315) (206,020) (59,375) (62,849) Fund Status and net plan liability recognized at December 31 $ (221,342) $ (212,129) $ (63,808) $ (67,679) 1 At December 31, 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. The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Other ( Thousands of dollars ) 2023 2022 2023 2022 Benefit obligation at December 31 $ 133,822 $ 122,915 $ 115 $ 107 Fair value of plan assets at December 31 119,236 115,862 – – Net plan liabilities recognized (14,586) (7,053) (115) (107) Net periodic benefit expense (benefit) 1,387 (5,322) (44) 62
Schedule of Amounts Included in Accumulated Other Comprehensive Loss Not Recognized in Net Periodic Benefit Expense	At December 31, 2023, amounts included in “Accumulated other comprehensive loss” (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table. ( Thousands of dollars ) Pension Other Net actuarial gain (loss) $ (202,868) $ 44,165 Prior service (credit) cost (20,561) 3,937 $ (223,429) $ 48,102
Schedule of Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets	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 ) 2023 2022 2023 2022 2023 2022 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 534,751 $ 511,375 $ 523,096 $ 499,338 $ 461,363 $ 434,283 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 151,146 141,917 148,661 139,634 – – Unfunded other postretirement plans 63,808 67,679 63,808 67,679 – –
Schedule of Components of Net Periodic Benefit Expense	The table that follows provides the components of net periodic benefit expense for each of the three years presented. Pension Benefits Other ( Thousands of dollars ) 2023 2022 2021 2023 2022 2021 Service cost $ 6,542 $ 7,875 $ 8,199 $ 495 $ 968 $ 1,295 Interest cost 34,140 22,747 14,784 3,241 2,211 2,071 Expected return on plan assets (32,839) (36,458) (19,222) – – – Amortization of prior service cost (credit) 620 (684) 591 (532) (532) – Recognized actuarial (gain) loss 9,776 16,098 20,565 (3,512) (615) (29) Net periodic benefit expense 18,239 9,578 24,917 (308) 2,032 3,337 Curtailment expense 219 – – – – – Total net periodic benefit expense $ 18,458 $ 9,578 $ 24,917 $ (308) $ 2,032 $ 3,337
Schedule of Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense	The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2023 and 2022 and net periodic benefit expense for 2023 and 2022. Benefit Obligations Net Periodic Benefit Expense Pension Other Pension Other December 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 % – –
Schedule of Benefit Payments Expected to be Paid in Future Years	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 Other 2024 $ 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
Schedule of Weighted Average Asset Allocation for Funded Pension Benefit Plans	The weighted average asset allocation for the Company’s funded pension benefit plans at the respective balance sheet dates are shown 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 %
Schedule of Fair Value Measurements of Retirement Plan Assets	At December 31, 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, Quoted Prices Significant Significant 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 At December 31, 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, Quoted Prices Significant Significant 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
Schedule of Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets	The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: ( Thousands of dollars ) Hedged Funds and Other Total at December 31, 2021 $ 82,854 Actual return on plan assets: Relating to assets held at the reporting date (38,389) Purchases, sales and settlements (11,731) Total at December 31, 2022 32,734 Actual return on plan assets: Relating to assets held at the reporting date 711 Relating to assets sold during the period (8,991) Total at December 31, 2023 $ 24,454

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
Financial Instruments and Risk Management (Tables)	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments	The gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments for each of the three years presented are shown in the following table. Gain (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)

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
Earnings Per Share (Tables)	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share	The following table reconciles the weighted-average shares outstanding used for these computations. ( Weighted-average shares ) 2023 2022 2021 Basic method 155,233,560 155,276,533 154,290,741 Dilutive stock options and restricted stock units ¹ 1,412,869 2,198,305 – Diluted method 156,646,429 157,474,838 154,290,741 1 Due to a net loss recognized by the Company for the year ended December 31, 2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
Schedule of Anti Dilutive Securities Not Included in Computation of Diluted EPS	The following table reflects certain options to purchase shares of common stock that were outstanding during each of the three years presented but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive. 2023 2022 2021 Antidilutive stock options excluded from diluted shares – 126,000 1,420,992 Weighted average price of these options – $49.65 $35.30

Other Financial Information (Ta

Other Financial Information (Tables)	12 Months Ended
Other Financial Information (Tables)	Dec. 31, 2023
Other Financial Information [Abstract]
Schedule of Noncash Operating Working Capital (Increase) Decrease	Noncash operating working capital (increased) decreased during each of the three years presented as shown in the following table. ( 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 1 Excludes receivable/payable balances relating to mark-to-market of crude contracts.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
Accumulated Other Comprehensive Loss (Tables)	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Components of Accumulated Other Comprehensive Loss	The components of AOCL on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table. ( Thousands of dollars ) Foreign Retirement and 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 $5.6 million and $15.3 million are included in the computation of net periodic benefit expense in 2023 and 2022, respectively. See Note J for additional information. Related income taxes of $1.1 million and $3.3 million are included in income tax expense in 2023 and 2022, respectively.

Assets and Liabilities Measur_2

Assets and Liabilities Measured at Fair Value (Tables)	12 Months Ended
Assets and Liabilities Measured at Fair Value (Tables)	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis	The fair value measurements for these assets and liabilities for the respective periods presented are shown in the following table. 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
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments	The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2023 and 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 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 value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal. December 31, 2023 2022 ( Thousands of dollars ) Carrying Fair Carrying Fair Financial liabilities: Current and long-term debt $ 1,329,075 $ 1,265,185 $ 1,823,139 $ 1,668,216

Common Stock Issued and Outst_2

Common Stock Issued and Outstanding (Tables)	12 Months Ended
Common Stock Issued and Outstanding (Tables)	Dec. 31, 2023
Equity [Abstract]
Schedule of Activity in Number of Shares of Common Stock Issued and Outstanding	Activity in the number of shares of common stock issued and outstanding for each of the three years presented is shown below. ( Number of shares outstanding ) 2023 2022 2021 Beginning of year 155,467,319 154,463,050 153,598,625 Stock options exercised 1 2,657 181,655 32,554 Restricted stock awards 1 689,824 822,614 831,871 Treasury shares purchased (3,411,158) – – End of year 152,748,642 155,467,319 154,463,050 1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon issuance of shares.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
Business Segments (Tables)	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Revenue by Major Customers	Customers that accounted for 10% or more of the Company’s sales 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
Schedule of Segment Information	Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate Discontinued Consolidated Year 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) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate Discontinued Consolidated Income 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 a noncontrolling interest in MP GOM. Geographic Information Certain long-lived assets at December 31 1 ( Millions of dollars ) United Canada 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, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2023
Leases [Abstract]
Summary of Lease Expenses, Term and Discount Rate	Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows: Year Ended December 31, (Thousands of dollars) Financial Statement Category 2023 2022 Operating lease 1, 2 Lease operating expenses $ 246,721 $ 217,038 Operating lease 2 Transportation, gathering and processing 37,797 39,669 Operating lease 2 Selling and general expense 9,859 8,003 Operating lease 2 Other operating expense 675 510 Operating lease 2 Exploration expenses 110,577 10,019 Operating lease 2 Property, plant and equipment 204,595 196,829 Operating lease 2 Asset 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 1 Variable lease expenses. For the years ended December 31, 2023 and 2022, 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. 2 Short-term leases due within 12 months. For the year ended December 31, 2023, includes $78.2 million in LOE, $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. Lease Term and Discount Rate December 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 %
Schedule of Maturity of Operating Leases	Maturity 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.
Schedule of Maturity of Finance Leases	Maturity 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.
Summary of Other Lease Information	Other Information Year 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.

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited) (Tables)	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Summary of Proved Reserves Based on Average Prices	Equivalents ( Millions of barrels of oil equivalent ) Total United Canada 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 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. 2 Includes proved developed reserves of 12.8 MMBOE, consisting of 11.7 MMBBL oil, 0.5 MMBBL NGLs and 3.8 BCF natural gas attributable to the noncontrolling interest in MP GOM. 3 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. ( Millions of barrels ) Total United Canada 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 United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 11.7 MMBBL for Total and United 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 noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. ( Millions of barrels ) Total United Canada 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. ( Billions of cubic feet ) Total United Canada 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 1,4 2,556.2 293.1 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 2,4 1,279.3 212.4 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.
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	( Millions of dollars ) United Canada 1 Other 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 2021 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 life extension project.
Schedule of Results of Operations for Oil and Gas Producing Activities	( Millions of dollars ) United Canada 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 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. ( Millions of dollars ) United Canada 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 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.
schedule of Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	( Millions of dollars ) United Canada Other Total December 31, 2023 Future cash inflows $ 18,927.6 $ 8,012.7 $ 1,004.2 $ 27,944.5 Future development costs (1,685.3) (769.6) (304.3) (2,759.2) Future production costs (7,856.2) (4,223.6) (288.7) (12,368.5) Future income taxes (1,057.5) (634.6) (121.3) (1,813.4) Future net cash flows 8,328.6 2,384.9 289.9 11,003.4 10% annual discount for estimated timing of cash flows (2,840.6) (1,056.9) (252.5) (4,150.0) Standardized measure of discounted future net cash flows $ 5,488.0 $ 1,328.0 $ 37.4 $ 6,853.4 December 31, 2022 Future cash inflows $ 27,277.9 $ 12,360.2 $ 59.2 $ 39,697.3 Future development costs (1,594.5) (642.4) (1.4) (2,238.3) Future production costs (8,297.4) (4,199.0) (12.1) (12,508.5) Future income taxes (2,606.8) (1,788.7) (5.4) (4,400.9) Future net cash flows 14,779.2 5,730.1 40.3 20,549.6 10% annual discount for estimated timing of cash flows (5,709.8) (3,015.6) (11.0) (8,736.4) Standardized measure of discounted future net cash flows $ 9,069.4 $ 2,714.5 $ 29.3 $ 11,813.2 December 31, 2021 Future cash inflows $ 18,449.1 $ 7,203.5 $ 44.0 $ 25,696.7 Future development costs (1,164.3) (521.1) (1.5) (1,686.8) Future production costs (7,140.6) (3,525.8) (9.1) (10,675.4) Future income taxes (1,024.4) (565.4) (3.0) (1,592.8) Future net cash flows 9,119.9 2,591.3 30.4 11,741.6 10% annual discount for estimated timing of cash flows (3,264.9) (1,169.3) (8.5) (4,442.7) Standardized measure of discounted future net cash flows $ 5,855.1 $ 1,422.0 $ 21.9 $ 7,299.0 1 Includes noncontrolling interest in MP GOM. 2 Totals within the table may not add as a result of rounding.
Schedule of Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows	The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. ( 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).
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities	( Millions of dollars ) United Canada 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

Supplemental Quarterly Inform_2

Supplemental Quarterly Information (Unaudited) (Tables)	12 Months Ended
Supplemental Quarterly Information (Unaudited) (Tables)	Dec. 31, 2023
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Quarterly Information	( Millions of dollars except per share amounts ) First Second Third Fourth Year 1 Year 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 1 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 each quarterly computation is based on the weighted average of common shares outstanding.

Significant Accounting Police_2

Significant Accounting Polices (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Significant Accounting Policies [Line Items]
Impairment of assets	$ 0	$ 0	$ 196,296
Performance Based Restricted Stock
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	3 years
Petrobas America Inc
Significant Accounting Policies [Line Items]
Percentage of acquired entity reported	100%
Percentage of acquired entity noncontrolling interest reported	20%
Minimum \| Stock Options
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	2 years
Minimum \| Investments In Affiliates
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	20%
Maximum \| Stock Options
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	3 years
Maximum \| Investments In Affiliates
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	50%

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) segment revenueStream	Dec. 31, 2022 USD ($)
Revenue from Contract with Customer [Abstract]
Number of geographic segments (in segments) \| segment	2
Number of revenue streams (in revenue stream) \| revenueStream	3
Receivables from contracts with customers \| $	$ 193.7	$ 201.1

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 842,200	$ 953,800	$ 812,900	$ 840,000	$ 986,100	$ 1,166,400	$ 1,196,200	$ 871,400	$ 3,448,854	$ 4,220,140	$ 2,801,215
(Loss) gain on crude contracts									0	(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
Revenue from production
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									3,376,639	4,038,451	2,801,215
Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									2,916,252	3,357,848	2,322,593
Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									89,526	142,777	110,975
Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									370,861	537,826	367,647
Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									72,215	181,689	0
United States \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									676,139	856,219	626,136
United States \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									33,178	64,015	50,189
United States \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									21,346	64,037	39,803
United States Offshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									2,072,353	2,229,658	1,478,993
United States Offshore \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									47,434	60,424	44,411
United States Offshore \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									71,332	161,160	81,944
United States Offshore \| Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									0	204	0
Canada \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									78,088	131,400	119,799
Canada \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									8,914	18,338	16,375
Canada \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									278,183	312,629	245,900
Canada \| Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									72,215	181,485	0
Canada Offshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									78,650	117,747	92,741
Other \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									$ 11,022	$ 22,824	$ 4,924

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Current Long-Term Contracts Outstanding (Details) - Canada	Dec. 31, 2023 MMcf
Contracts to sell natural gas at USD index pricing \| End Date, Quarter 4, 2025
Disaggregation of Revenue [Line Items]
Approximate Volumes	25
Contracts to sell natural gas at USD index pricing \| End Date Quarter 4 2024
Disaggregation of Revenue [Line Items]
Approximate Volumes	31
Contracts to sell natural gas at USD index pricing \| End Date Quarter42024 No.2
Disaggregation of Revenue [Line Items]
Approximate Volumes	25
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 2026
Disaggregation of Revenue [Line Items]
Approximate Volumes	49
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 2027
Disaggregation of Revenue [Line Items]
Approximate Volumes	30
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 2028
Disaggregation of Revenue [Line Items]
Approximate Volumes	10
Contracts to sell natural gas at CAD fixed pricing \| End Date Quarter 4 2024
Disaggregation of Revenue [Line Items]
Approximate Volumes	124
Contracts to sell natural gas at CAD fixed pricing \| End Date Quarter42024 No.3
Disaggregation of Revenue [Line Items]
Approximate Volumes	28

Property, Plant and Equipment -

Property, Plant and Equipment - Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Cost	$ 21,360,582	$ 20,717,987
Net	8,225,197	8,228,016
Exploration and Production
Property, Plant and Equipment [Line Items]
Cost	21,228,490	20,567,489
Net	8,201,475	8,204,463
Corporate and other
Property, Plant and Equipment [Line Items]
Cost	132,092	150,498
Net	23,722	23,553
Mineral Rights
Property, Plant and Equipment [Line Items]
Cost	351,000	476,981
Net	228,329	344,507
Administrative Assets and Support Equipment
Property, Plant and Equipment [Line Items]
Net	$ 15,356	$ 18,319

Property, Plant and Equipment_2

Property, Plant and Equipment - Narrative (Details) $ in Millions			1 Months Ended		3 Months Ended	12 Months Ended
	Sep. 15, 2023 USD ($)	Sep. 15, 2023 CAD ($)	Aug. 31, 2022 USD ($)	Jun. 30, 2022 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Property, Plant and Equipment [Line Items]
Impairment of assets						$ 0	$ 0	$ 196,296,000
Impairment of assets						0	0	196,296,000
Amount						49,118,000	171,860,000	179,481,000	$ 181,616,000
Reclassifications to proved properties based on the determination of proved reserves						82,185,000	7,915,000	0
Capitalized exploration well costs charged to expense						40,605,000	33,146,000	18,860,000
Well costs incurred and expensed						129,200,000
Exploratory well costs capitalized more than one year						49,100,000
Lucius Field
Property, Plant and Equipment [Line Items]
Percentage of field acquired			3.37%
Consideration transferred			$ 78,500,000
Kodak Field
Property, Plant and Equipment [Line Items]
Percentage of field acquired				11%
Consideration transferred				$ 50,000,000
Discontinued Operations, Disposed of by Sale \| Thunder Hawk field
Property, Plant and Equipment [Line Items]
Percentage of ownership sold					62.50%
Cash received from divestiture					$ 20,000,000
Closing adjustment					23,100,000
Net payment					3,100,000
Gain on sale					17,900,000
Discontinued Operations, Disposed of by Sale \| Thunder Hawk field \| Buyer
Property, Plant and Equipment [Line Items]
Impairment of assets					47,900,000
Discontinued Operations, Disposed of by Sale \| CA-2 Asset
Property, Plant and Equipment [Line Items]
Gain on sale					0
Contingent consideration value					$ 8,700,000
Canada
Property, Plant and Equipment [Line Items]
Proceeds from sale of property, plant, and equipment		$ 139
Gain (loss) on sale of property plant equipment	$ 0
Impairment of assets						0	$ 0	$ 171,296,000
Exploratory well costs capitalized more than one year						4,800,000
U.S.
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year						26,500,000
Vietnam
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year						15,100,000
Brunei
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year						$ 2,700,000

Property, Plant and Equipment_3

Property, Plant and Equipment - Recognized Impairments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Impairment of assets	$ 0	$ 0	$ 196,296
Corporate
Property, Plant and Equipment [Line Items]
Impairment of assets	0	0	7,000
Canada
Property, Plant and Equipment [Line Items]
Impairment of assets	0	0	171,296
Other Foreign
Property, Plant and Equipment [Line Items]
Impairment of assets	$ 0	$ 0	$ 18,000

Property, Plant And Equipment_4

Property, Plant And Equipment - Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
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)	(7,915)	0
Capitalized exploration well costs charged to expense	(40,605)	(33,146)	(18,860)
Ending balance at December 31	$ 49,118	$ 171,860	$ 179,481

Property, Plant And Equipment_5

Property, Plant And Equipment - Aging of Capitalized Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) project well	Dec. 31, 2022 USD ($) well project	Dec. 31, 2021 USD ($) project well	Dec. 31, 2020 USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 49,118	$ 171,860	$ 179,481	$ 181,616
No. of wells (in wells) \| well	4	9	14
No. of projects (in projects) \| project	4	8	8
Zero to one year
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 0	$ 15,527	$ 13,273
No. of wells (in wells) \| well	0	2	3
No. of projects (in projects) \| project	0	2	3
One to two years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 0	$ 13,307	$ 0
No. of wells (in wells) \| well	0	2	0
No. of projects (in projects) \| project	0	2	0
Two to three years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 2,698	$ 0	$ 53,070
No. of wells (in wells) \| well	1	0	5
No. of projects (in projects) \| project	1	0	5
Three years or more
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 46,420	$ 143,026	$ 113,138
No. of wells (in wells) \| well	3	5	6
No. of projects (in projects) \| project	3	4	0

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Unsold crude oil	$ 10,304	$ 6,546
Materials and supplies	44,150	47,967
Inventories	$ 54,454	$ 54,513

Financing Arrangements and De_3

Financing Arrangements and Debt - Schedule of Long Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
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
Debt and Lease Obligation, Total	1,329,075	1,823,139
Current maturities	(723)	(687)
Long-term debt, including finance lease obligation	$ 1,328,352	$ 1,822,452
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation
5.75% notes, due August 2025
Debt Instrument [Line Items]
Total notes payable	$ 0	$ 248,675
5.75% notes, due August 2025 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.75%
5.875% notes, due December 2027
Debt Instrument [Line Items]
Total notes payable	$ 443,249	543,249
5.875% notes, due December 2027 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.875%
6.375% notes, due July 2028
Debt Instrument [Line Items]
Total notes payable	$ 372,226	451,934
6.375% notes, due July 2028 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.375%
7.05% notes, due May 2029
Debt Instrument [Line Items]
Total notes payable	$ 179,708	250,000
7.05% notes, due May 2029 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.05%
5.875% Notes, Due December 2042
Debt Instrument [Line Items]
Total notes payable	$ 339,761	$ 339,761
Debt instrument, basis spread on variable rate	0.25%
5.875% Notes, Due December 2042 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.875%

Financing Arrangements and De_4

Financing Arrangements and Debt - Narrative (Details)	1 Months Ended			2 Months Ended	12 Months Ended
Financing Arrangements and Debt - Narrative (Details)	Nov. 30, 2023 USD ($)	Sep. 30, 2023 USD ($)	Nov. 30, 2022 USD ($) consecutiveTradingDay	Oct. 31, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2022 USD ($)	Aug. 31, 2022 USD ($)	Jun. 30, 2022 USD ($)
Line of Credit Facility [Line Items]
Future maturities of long term debt in 2024					$ 0
Future maturities of long term debt in 2025					0
Future maturities of long term debt in 2026					0
Future maturities of long term debt in 2027					443,200,000
Future maturities of long term debt in 2028					372,200,000
Future maturities of long term debt, thereafter					519,500,000
Debt extinguishment cost					0	$ 8,295,000	$ 39,335,000
Early repayment of senior debt					498,175,000	647,707,000	$ 876,358,000
Senior Notes Due 2028
Line of Credit Facility [Line Items]
Repurchase amount									$ 98,100,000
6.125% Notes Due 2042
Line of Credit Facility [Line Items]
Repurchase amount								$ 9,200,000
Cost of debt extinguishment					0
Early repayment of senior debt				$ 7,200,000
Stated interest rate										6.125%
6.875% Notes Due 2024
Line of Credit Facility [Line Items]
Repurchase amount		$ 248,700,000							$ 42,400,000	$ 200,000,000
Cost of debt extinguishment					4,300,000
Debt extinguishment cost					3,400,000
Stated interest rate									6.875%	6.875%
5.750% Notes Due 2025
Line of Credit Facility [Line Items]
Cost of debt extinguishment					3,900,000
Debt extinguishment cost					2,900,000
Senior Notes Due 2025
Line of Credit Facility [Line Items]
Repurchase amount									$ 100,000,000
Base Rate
Line of Credit Facility [Line Items]
Business days \| consecutiveTradingDay			2
Senior Notes
Line of Credit Facility [Line Items]
Repurchase amount	$ 249,500,000
Extinguishment of debt	$ 250,000,000
Cost of debt extinguishment		$ 900,000			1,300,000	$ 4,000,000
Senior Notes \| Senior Notes due 2025 and 2028
Line of Credit Facility [Line Items]
Debt extinguishment cost					2,000,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Transaction costs			$ 14,400,000
Revolving Credit Facility \| Base Rate
Line of Credit Facility [Line Items]
Stated interest rate			0.50%
Revolving Credit Facility \| Adjusted Term SOFR Rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			1%
Revolving Credit Facility \| Adjusted Daily Simple SOFR Rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			0.10%
Revolving Credit Facility \| Daily Simple SOFR [Member]
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			0.10%
Revolving Credit Facility \| Unsecured Debt
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity			$ 800,000,000
Amount outstanding					$ 0
Interest rate on credit facility					7.70%
Revolving Credit Facility \| Unsecured Debt \| Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding					$ 3,800,000
Revolving Credit Facility \| Unsecured Debt \| Maximum
Line of Credit Facility [Line Items]
Debt instrument, consolidated leverage ratio			3.50
Revolving Credit Facility \| Unsecured Debt \| Minimum
Line of Credit Facility [Line Items]
Debt instrument, consolidated interest coverage ratio			2.50

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 911,653	$ 971,893
Accretion	46,059	46,243	$ 46,613
Liabilities incurred	20,628	46,449
Revisions of previous estimates	29,056	(78,229)
Liabilities settled	(95,637)	(64,255)
Changes due to translation of foreign currencies	3,004	(10,448)
Balance at end of year	$ 914,763	$ 911,653	$ 971,893

Asset Retirement Obligations _2

Asset Retirement Obligations - Classification of Asset of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Balance at end of year	$ 914,763	$ 911,653	$ 971,893
Current portion of liability at end of year	(10,712)	(94,385)
Asset retirement obligations	$ 904,051	$ 817,268

Income Taxes - Components of In

Income Taxes - Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income (loss) from continuing operations before income taxes
United States									$ 901,761	$ 1,306,200	$ 114,659
Foreign									19,308	144,061	(71,768)
Income from continuing operations before income taxes	$ 169,500	$ 356,300	$ 127,300	$ 267,900	$ 282,700	$ 734,000	$ 515,500	$ (81,900)	921,069	1,450,261	42,891
Income tax expense (benefit)
U.S. Federal – Current									0	0	0
Federal - Deferred									170,115	234,749	(1,480)
Total U.S. Federal									170,115	234,749	(1,480)
State									6,622	9,010	3,303
Foreign – Current									13,182	18,134	(5,158)
Foreign - Deferred									6,002	47,571	(2,527)
Total Foreign									19,184	65,705	(7,685)
Total income tax expense (benefit)									$ 195,921	$ 309,464	$ (5,862)

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Rates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
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	0	0	(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 income tax expense (benefit)	$ 195,921	$ 309,464	$ (5,862)

Income Taxes - Analysis of Defe

Income Taxes - Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets
Property and leasehold costs	$ 240,065	$ 242,467
Liabilities for dismantlements	34,258	31,017
Postretirement and other employee benefits	82,437	86,798
U. S. net operating loss	357,490	442,699
Investment in partnership	14,655	11,595
Other deferred tax assets	48,778	111,212
Total gross deferred tax assets	777,683	925,788
Less valuation allowance	(146,861)	(136,008)
Net deferred tax assets	630,822	789,780
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)	(5,000)
Accumulated depreciation, depletion and amortization	(847,981)	(796,510)
Other deferred tax liabilities	(54,052)	(85,284)
Total gross deferred tax liabilities	(907,033)	(886,794)
Net deferred tax (liabilities) assets	$ (276,211)	$ (97,014)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Line Items]
Increase (decrease) in deferred tax asset valuation allowance	$ 10,900
U. S. net operating loss	357,490	$ 442,699
Earnings expected to be repatriated in next fiscal year	100,000
Deferred tax liability, undistributed foreign earnings	5,000	5,000
Undistributed foreign earnings	1,500,000
Other recorded liabilities for interest and penalties	300	$ 300	$ 300
Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 1,700,000

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	$ 3,928	$ 2,903	$ 2,832
Additions for tax positions related to current year	0	77	71
Additions for tax positions related to prior year	2,456	948	0
Balance at December 31	$ 6,384	$ 3,928	$ 2,903

Incentive Plans - Narrative (De

Incentive Plans - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed	$ 47,400
Settlement period of phantom units	3 years
Option term	7 years
Total intrinsic value of options exercised	$ 160
Cash settled awards	29,400	$ 49,300	$ 18,200
Incentive compensation plan expense	$ 30,900	$ 42,900	$ 29,000
Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	2 years
Vesting percentage	50%
Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vesting percentage	50%
Performance Based Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return, weighted percentage of PSU	0.80
EBITDA divided by average capital employed, weighted percentage of PSU	0.20
Vesting period	3 years
2020 Long-Term Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares available for issuance (in shares)	5,000,000
Number of shares available (in shares)	2,100,000
2012 Long-Term Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option term	7 years

Incentive Plans - Share-Based P

Incentive Plans - Share-Based Plans, Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Compensation charged against income before income tax benefit	$ 58,760	$ 74,587	$ 43,660
Related income tax benefit recognized in income	$ 9,330	$ 12,710	$ 7,196

Incentive Plans - Changes in Pe

Incentive Plans - Changes in Performance-Based RSU Outstanding (Details) - Equity-Settled Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	2,148,467	2,670,756	2,207,429
Granted (in shares)	409,160	595,700	1,156,800
Vested and issued (in shares)	(408,135)	(654,177)	(642,473)
Forfeited (in shares)	(331,304)	(463,812)	(51,000)
Outstanding at end of year (in shares)	1,818,188	2,148,467	2,670,756

Incentive Plans - Assumptions u

Incentive Plans - Assumptions used in Valuation Performance Awards Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Performance Based Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)			$ 16.03
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility	81%		74%
Expected volatility rate minimum		79%
Expected volatility rate maximum		81%
Risk-free interest rate			0.18%
Stock beta	1.034		1.169
Stock beta minimum		119.50%
Stock beta maximum		120%
Expected life	3 years	3 years	3 years
Performance Based Restricted Stock \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)		$ 37.77
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	3.90%	1.39%
Performance Based Restricted Stock \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	$ 60.46	$ 47.37
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate		2.85%
Time lapse restricted stock \| Non-employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	43.27	$ 32.84
Time lapse restricted stock \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	$ 42.20		$ 12.30
Time lapse restricted stock \| Minimum \| Non-employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)			13.14
Time lapse restricted stock \| Minimum \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)		29.80
Time lapse restricted stock \| Maximum \| Non-employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)			$ 23.58
Time lapse restricted stock \| Maximum \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)		$ 49.86

Incentive Plans - Changes in Ti

Incentive Plans - Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding (Details) - Restricted Stock and Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	1,227,792	1,451,438	1,383,043
Granted (in shares)	556,100	416,492	573,907
Vested and issued (in shares)	(517,047)	(462,418)	(476,012)
Forfeited (in shares)	(47,261)	(177,720)	(29,500)
Outstanding at end of year (in shares)	1,219,584	1,227,792	1,451,438

Incentive Plans - Changes in St

Incentive Plans - Changes in Stock Options Outstanding (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Number of Shares
Exercised (in shares)	(2,657)	(181,655)	(32,554)
Stock Options
Number of Shares
Outstanding at beginning of year (in shares)	13,000	1,319,500	2,048,400
Exercised (in shares)	(11,000)	(760,500)	(170,000)
Forfeited (in shares)	(2,000)	(546,000)	(558,900)
Outstanding at end of year (in shares)	0	13,000	1,319,500
Exercisable at end of year (in shares)	0	13,000	1,319,500	2,048,400
Average Exercise Price
Outstanding at beginning of year (in USD per share)	$ 28.51	$ 37.77	$ 40.14
Exercised (in USD per share)	28.51	23.29	17.57
Forfeited (in USD per share)	28.51	49.65	52.61
Outstanding at end of year (in USD per share)	0	28.51	37.77
Exercisable at end of year (in USD per share)	$ 0	$ 28.51	$ 34.25	$ 37.88

Employee and Retiree Benefit _3

Employee and Retiree Benefit Plans - Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in plan assets
Beginning balance	$ 450,944
Ending balance	477,809	$ 450,944
Pension Benefits
Change in benefit obligation
Beginning balance	663,073	939,380
Service cost	6,542	7,875	$ 8,199
Interest cost	34,140	22,747	14,784
Participant contributions	0	0
Actuarial loss (gain)	26,625	(238,407)
Medicare Part D subsidy	0	0
Exchange rate changes	6,089	(21,018)
Benefits paid	(56,296)	(47,504)
Plan amendments	18,978	0
Ending balance	699,151	663,073	939,380
Change in plan assets
Beginning balance	450,944	611,302
Actual return on plan assets	39,953	(133,395)
Employer contributions	37,546	41,145
Participant contributions	0	0
Medicare Part D subsidy	0	0
Exchange rate changes	5,662	(20,604)
Benefits paid	(56,296)	(47,504)
Ending balance	477,809	450,944	611,302
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	3,192	3,584
Other accrued liabilities	(10,219)	(9,693)
Deferred credits and other liabilities	(214,315)	(206,020)
Funded status and net plan liability recognized at December 31	(221,342)	(212,129)
Other Postretirement Benefits
Change in benefit obligation
Beginning balance	67,679	96,133
Service cost	495	968	1,295
Interest cost	3,241	2,211	2,071
Participant contributions	2,629	2,283
Actuarial loss (gain)	(5,567)	(29,533)
Medicare Part D subsidy	299	331
Exchange rate changes	2	(20)
Benefits paid	(4,970)	(4,694)
Plan amendments	0	0
Ending balance	63,808	67,679	96,133
Change in plan assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	2,042	2,080
Participant contributions	2,629	2,283
Medicare Part D subsidy	299	331
Exchange rate changes	0	0
Benefits paid	(4,970)	(4,694)
Ending balance	0	0	$ 0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	0	0
Other accrued liabilities	(4,433)	(4,830)
Deferred credits and other liabilities	(59,375)	(62,849)
Funded status and net plan liability recognized at December 31	$ (63,808)	$ (67,679)

Employee and Retiree Benefit _4

Employee and Retiree Benefit Plans - Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	$ (202,868)
Prior service (credit) cost	(20,561)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(223,429)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	44,165
Prior service (credit) cost	3,937
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 48,102

Employee and Retiree Benefit _5

Employee and Retiree Benefit Plans - Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Funded plan \| Qualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 534,751	$ 511,375
Accumulated Benefit Obligations	523,096	499,338
Fair Value of Plan Assets	461,363	434,283
Unfunded plan \| Other postretirement plans
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	63,808	67,679
Accumulated Benefit Obligations	63,808	67,679
Fair Value of Plan Assets	0	0
Unfunded plan \| Nonqualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	151,146	141,917
Accumulated Benefit Obligations	148,661	139,634
Fair Value of Plan Assets	$ 0	$ 0

Employee and Retiree Benefit _6

Employee and Retiree Benefit Plans - Components of Net Periodic Benefit Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 6,542	$ 7,875	$ 8,199
Interest cost	34,140	22,747	14,784
Expected return on plan assets	(32,839)	(36,458)	(19,222)
Amortization of prior service cost (credit)	620	(684)	591
Recognized actuarial (gain) loss	9,776	16,098	20,565
Net periodic benefit expense	18,239	9,578	24,917
Curtailment expense	219	0	0
Total net periodic benefit expense	18,458	9,578	24,917
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	495	968	1,295
Interest cost	3,241	2,211	2,071
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	(532)	(532)	0
Recognized actuarial (gain) loss	(3,512)	(615)	(29)
Net periodic benefit expense	(308)	2,032	3,337
Curtailment expense	0	0	0
Total net periodic benefit expense	$ (308)	$ 2,032	$ 3,337

Employee and Retiree Benefit _7

Employee and Retiree Benefit Plans - Amount Related to Foreign Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	$ 477,809	$ 450,944
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	119,236	115,862
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	699,151	663,073	$ 939,380
Fair value of plan assets at December 31	477,809	450,944	611,302
Net plan liabilities recognized	(221,342)	(212,129)
Net periodic benefit expense (benefit)	18,458	9,578	24,917
Pension Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	133,822	122,915
Fair value of plan assets at December 31	119,236	115,862
Net plan liabilities recognized	(14,586)	(7,053)
Net periodic benefit expense (benefit)	1,387	(5,322)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	63,808	67,679	96,133
Fair value of plan assets at December 31	0	0	0
Net plan liabilities recognized	(63,808)	(67,679)
Net periodic benefit expense (benefit)	(308)	2,032	$ 3,337
Other Postretirement Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	115	107
Fair value of plan assets at December 31	0	0
Net plan liabilities recognized	(115)	(107)
Net periodic benefit expense (benefit)	$ (44)	$ 62

Employee and Retiree Benefit _8

Employee and Retiree Benefit Plans - Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.40%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.03%	5.30%
Net periodic benefit expense, discount rate	5.27%	3.13%
Benefit obligation, rate of compensation increase	3.52%	3.50%
Net periodic benefit expense, rate of compensation increase	3.52%	3%
Benefit obligation, cash balance interest credit rate	3.20%	3.20%
Net periodic benefit cost, cash balance interest credit rate	0%	0%
Benefit obligation, expected return on Plan assets	0%	0%
Expected return on plan assets	7.35%	6.24%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.15%	5.41%
Net periodic benefit expense, discount rate	5.41%	2.86%
Benefit obligation, rate of compensation increase	0%	0%
Net periodic benefit expense, rate of compensation increase	0%	0%
Benefit obligation, cash balance interest credit rate	0%	0%
Net periodic benefit cost, cash balance interest credit rate	0%	0%
Benefit obligation, expected return on Plan assets	0%	0%
Expected return on plan assets	0%	0%

Employee and Retiree Benefit _9

Employee and Retiree Benefit Plans - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) investment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Future annual rate of increase in cost of health care to measure postretirement benefit obligations	7.40%
Ultimate rate of health care cost	4%
Weighted average expected return on plan asset	7.40%
Basis used to determine expected return on plan asset, average expected investment expenses	0.80%
Perentage return on plan assets over the last ten years	3%
Number of investments in hedge funds and other alternative investments (in investments) \| investment	2
Defined benefit plan, percentage of employer's matching contribution	6%
Thrift plan expense	$ 8,500	$ 6,000	$ 5,400
Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	8.40%
Equity securities \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40%
Equity securities \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	75%
Fixed income securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	4.70%
Fixed income securities \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	20%
Fixed income securities \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60%
Other \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0%
Other \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15%
Cash equivalents \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0%
Cash equivalents \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	20%
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Cash balance interest accumulation rate	1.89%
Contributions to benefit plans	$ 37,546	$ 41,145
Weighted average expected return on plan asset	7.35%	6.24%
Pension Benefits \| U.S.
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 34,700
Contributions to benefit plans, next fiscal year	35,800
Pension Benefits \| Foreign Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans, next fiscal year	2,200
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 2,042	$ 2,080
Weighted average expected return on plan asset	0%	0%
Other Postretirement Benefits \| U.S.
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 2,000
Contributions to benefit plans, next fiscal year	$ 4,400
Second investment
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	90 days
Third investment
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	95 days
Domestic plan, investment lock up period	3 years

Employee and Retiree Benefit_10

Employee and Retiree Benefit Plans - Benefit Payments Expected to be Paid in Future Years (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	$ 47,042
2025	47,424
2026	48,004
2027	48,481
2028	49,834
2029-2033	248,023
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	4,433
2025	4,456
2026	4,479
2027	4,491
2028	4,614
2029-2033	$ 22,037

Employee and Retiree Benefit_11

Employee and Retiree Benefit Plans - Weighted Average Asset Allocation for Funded Pension Benefit Plans (Details)	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100%	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	62.60%	65.70%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	29.10%	23.40%
Alternatives
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	5.10%	7.30%
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	3.20%	3.60%

Employee and Retiree Benefit_12

Employee and Retiree Benefit Plans - Fair Value Measurements of Retirement Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	$ 477,809	$ 450,944
Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	278,515	273,447
Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	174,841	144,763
Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	24,454	32,734
U.S.
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	358,573	335,082
U.S. \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	278,515	273,447
U.S. \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	76,227	49,528
U.S. \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	3,831	12,106
U.S. \| U.S. core equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	105,212	96,433
U.S. \| U.S. core equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	105,212	96,433
U.S. \| U.S. core equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| U.S. core equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	64,165	64,421
U.S. \| U.S. small/midcap \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	64,165	64,421
U.S. \| U.S. small/midcap \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| U.S. small/midcap \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Other alternative strategies
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	3,831	12,106
U.S. \| Other alternative strategies \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Other alternative strategies \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Other alternative strategies \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	3,831	12,106
U.S. \| International equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	31,820	44,672
U.S. \| International equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	31,820	44,672
U.S. \| International equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| International equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Emerging market equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	10,525	13,541
U.S. \| Emerging market equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	10,525	13,541
U.S. \| Emerging market equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Emerging market equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	132,608	85,190
U.S. \| U.S. fixed income \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	56,381	35,661
U.S. \| U.S. fixed income \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	76,227	49,528
U.S. \| U.S. fixed income \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	10,412	18,719
U.S. \| Cash and equivalents \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	10,412	18,719
U.S. \| Cash and equivalents \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
U.S. \| Cash and equivalents \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	119,236	115,862
Foreign Plans \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	98,613	95,234
Foreign Plans \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	20,623	20,628
Foreign Plans \| Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	5,133	9,384
Foreign Plans \| Cash and equivalents \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Cash and equivalents \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	5,133	9,384
Foreign Plans \| Cash and equivalents \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Equity securities funds
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	24,389	23,877
Foreign Plans \| Equity securities funds \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Equity securities funds \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	24,389	23,877
Foreign Plans \| Equity securities funds \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Fixed income securities funds
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	23,930	30,727
Foreign Plans \| Fixed income securities funds \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Fixed income securities funds \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	23,930	30,727
Foreign Plans \| Fixed income securities funds \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Diversified pooled fund
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	45,162	31,246
Foreign Plans \| Diversified pooled fund \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Diversified pooled fund \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	45,162	31,246
Foreign Plans \| Diversified pooled fund \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Other
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	20,623	20,628
Foreign Plans \| Other \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Other \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
Foreign Plans \| Other \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	$ 20,623	$ 20,628

Employee and Retiree Benefit_13

Employee and Retiree Benefit Plans - Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	$ 450,944
Ending balance	477,809	$ 450,944
Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	32,734
Ending balance	24,454	32,734
Hedged Funds and Other Alternative Strategies \| Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	32,734	82,854
Relating to assets held at the reporting date	711	(38,389)
Purchases, sales and settlements	(8,991)	(11,731)
Ending balance	$ 24,454	$ 32,734

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Narrative (Details) barrels_per_day in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) barrels_per_day $ / bbl	Dec. 31, 2023 derivative	Dec. 31, 2022 derivative $ / bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount of loss reclassified to interest expense \| $	$ 2.1
Interest rate swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments held (in derivatives) \| derivative		0	0
Commodity swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and gas delivery commitments and contracts, daily production \| barrels_per_day	20
Derivative swap, average price (in USD per barrel)	44.88
Commodity collars
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and gas delivery commitments and contracts, daily production \| barrels_per_day	25
Commodity collars \| Maximum
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative swap, average price (in USD per barrel)			75.20
Commodity collars \| Minimum
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative swap, average price (in USD per barrel)			63.24
Foreign exchange contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments held (in derivatives) \| derivative		0	0

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Commodity swaps
Derivative Instruments, Gain (Loss) [Line Items]
(Loss) on derivative instruments	$ 0	$ (160,690)	$ (510,596)
Commodity collars
Derivative Instruments, Gain (Loss) [Line Items]
(Loss) on derivative instruments	$ 0	$ (159,721)	$ (15,254)

Earnings Per Share - Weighted-A

Earnings Per Share - Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Basic method (in shares)	155,233,560	155,276,533	154,290,741
Dilutive stock options (in shares)	1,412,869	2,198,305	0
Diluted method (in shares)	156,646,429	157,474,838	154,290,741
Unvested stock awards			$ 0	$ 0

Earnings Per Share - Anti Dilut

Earnings Per Share - Anti Dilutive Securities Not Included in Computation of Diluted EPS (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	0	126,000	1,420,992
Weighted average price of these options (in USD per share)	$ 0	$ 49.65	$ 35.30

Other Financial Information - N

Other Financial Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Financial Information [Abstract]
Net gains (losses) from foreign currency transactions	$ (10.8)	$ 23	$ 1

Other Financial Information -_2

Other Financial Information - Noncash Operating Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 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	(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
Capitalized interest paid	14,500	16,300	16,100
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

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	$ 5,148,893	$ 4,320,796
Before reclassifications to income	9,018	(18,973)
Reclassifications to income	4,551	11,998
Other comprehensive income (loss)	13,569	(6,975)	$ 73,622
Balance at end of year	5,549,653	5,148,893	4,320,796
Total
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(534,686)	(527,711)	(601,333)
Other comprehensive income (loss)	13,569	(6,975)
Balance at end of year	(521,117)	(534,686)	(527,711)
Foreign Currency Translation Gains (Losses)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(418,230)	(311,895)
Before reclassifications to income	36,598	(106,335)
Reclassifications to income	0	0
Other comprehensive income (loss)	36,598	(106,335)
Balance at end of year	(381,632)	(418,230)	(311,895)
Retirement and Postretirement Benefit Plan Adjustments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(116,456)	(215,816)
Before reclassifications to income	(27,580)	87,362
Reclassifications to income	4,551	11,998
Other comprehensive income (loss)	(23,029)	99,360
Balance at end of year	(139,485)	(116,456)	$ (215,816)
Reclassification before tax	5,600	15,300
Reclassification tax	$ 1,100	$ 3,300

Assets and Liabilities Measur_3

Assets and Liabilities Measured at Fair Value - Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	$ 17,785	$ 15,135
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	17,785	15,135
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Nonqualified employee savings plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	17,785	15,135
Nonqualified employee savings plan \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	17,785	15,135
Nonqualified employee savings plan \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Nonqualified employee savings plan \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	$ 0	$ 0

Assets and Liabilities Measur_4

Assets and Liabilities Measured at Fair Value - Narratives (Details) $ in Millions	Dec. 31, 2023 OffsettingPosition	Dec. 31, 2022 USD ($) OffsettingPosition	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Number of offsetting positions (in offsetting positions) \| OffsettingPosition	0	0
PAI and LLOG
Derivative liabilities		$ 192.7
LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. \| Sales thresholds 2019 to 2025
Contingent consideration, maximum			$ 200
LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. \| Net crude oil and condensate revenue
Contingent consideration, maximum			$ 50
Petrobas America Inc \| Sales thresholds 2019 to 2025
Contingent consideration, maximum				$ 150
Petrobas America Inc \| Enhanced oil recovery projects
Contingent consideration, maximum				$ 50

Assets and Liabilities Measur_5

Assets and Liabilities Measured at Fair Value - Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Carrying Amount
Current and long-term debt, carrying amount	$ 1,329,075	$ 1,823,139
Fair Value
Current and long-term debt, fair value	$ 1,265,185	$ 1,668,216

Commitments (Details)

Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
Commitments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	$ 244,622
Future rental payments, due year two	82,596
Future rental payments, due year three	63,703
Future rental payments, due year four	62,066
Future rental payments, due year five	61,229
Commitments for capital expenditures	209,800
Gulf of Mexico
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	173,300
Eagle Ford Shale
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	13,300
Canada
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	19,200
Other foreign
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	4,000
Processing production handling and transportation services
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	225,900
Future rental payments, due year two	126,000
Future rental payments, due year three	114,700
Future rental payments, due year four	103,500
Future rental payments, due year five	94,400
Processing and transportation charges	$ 295,100	$ 216,400	$ 151,800

Environmental and Other Conti_2

Environmental and Other Contingencies (Details) $ in Millions	Dec. 31, 2023 USD ($)
Environmental Remediation Obligations [Abstract]
Threshold for disclosure of monetary sanctions related to environmental proceedings	$ 1
Threshold for disclosure of monetary sanctions related to aware of legal environmental proceedings	$ 1

Common Stock Issued and Outst_3

Common Stock Issued and Outstanding - Number of Shares of Common Stock Issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning of year (in shares)	155,467,319	154,463,050	153,598,625
Stock options exercised (in shares)	2,657	181,655	32,554
Restricted stock awards (in shares)	689,824	822,614	831,871
Treasury shares purchased (in shares)	(3,411,158)	0	0
End of year (in shares)	152,748,642	155,467,319	154,463,050

Common Stock Issued and Outst_4

Common Stock Issued and Outstanding - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Nov. 02, 2023	Aug. 04, 2022
Equity [Abstract]
Stock repurchase program, authorized amount	$ 600,000,000			$ 151,200,000	$ 300,000,000
Treasury shares purchased (in shares)	3,411,158	0	0
Stock repurchase program, remaining amount				$ 450,000,000

Business Segments - Schedule of

Business Segments - Schedule of Revenue by Major Customers (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Chevron Corporation
Segment Reporting Information [Line Items]
Concentration risk	16%	19%	30%
ExxonMobil Corporation
Segment Reporting Information [Line Items]
Concentration risk	27%	12%

Business Segments - Narrative (

Business Segments - Narrative (Details)	Dec. 31, 2023 USD ($)
Segment Reporting [Abstract]
Assets held-for-sale	$ 0

Business Segments - Segment Inf

Business Segments - Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI	$ 139,700	$ 277,800	$ 91,900	$ 214,300	$ 220,600	$ 574,100	$ 409,500	$ (65,500)	$ 723,681	$ 1,138,719	$ 47,528
Revenues from external customers									3,460,147	3,932,662	2,299,281
Interest and other income (loss)									(8,587)	14,310	(16,771)
Interest expense, net of capitalization									(112,373)	(150,759)	(221,773)
Income tax expense (benefit)									195,921	309,464	(5,862)
Impairment of assets									0	0	196,296
Depreciation, depletion and amortization									861,602	776,817	795,105
Accretion of asset retirement obligations									46,059	46,243	46,613
Amortization of undeveloped leases									10,925	13,300	18,925
Deferred and noncurrent income taxes									179,823	286,079	(4,146)
Additions to property, plant, equipment									914,800	1,063,300	585,300
Total assets at year-end	9,766,697				10,308,952				9,766,697	10,308,952	10,304,900
Minimum
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from external customers									3,460,200
Income tax expense (benefit)									196,000
Depreciation, depletion and amortization									861,500
Total assets at year-end	9,766,600								9,766,600
Discontinued Operations
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									(1,500)	(2,100)	(1,200)
Revenues from external customers									0	0	0
Interest and other income (loss)									0	0	0
Interest expense, net of capitalization									0	0	0
Income tax expense (benefit)									0	0	0
Impairment of assets											0
Depreciation, depletion and amortization									0	0	0
Accretion of asset retirement obligations									0	0	0
Amortization of undeveloped leases									0	0	0
Deferred and noncurrent income taxes									0	0	0
Additions to property, plant, equipment									0	0	0
Total assets at year-end	800				800				800	800	800
Corporate and Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									(156,000)	(438,300)	(668,000)
Revenues from external customers									3,400	(314,400)	(519,400)
Interest and other income (loss)									(3,000)	23,300	(6,500)
Interest expense, net of capitalization									(111,900)	(150,400)	(221,600)
Income tax expense (benefit)									(41,800)	(107,800)	(178,600)
Impairment of assets											7,000
Depreciation, depletion and amortization									11,000	12,900	13,000
Accretion of asset retirement obligations									100	0	0
Amortization of undeveloped leases									0	0	0
Deferred and noncurrent income taxes									(50,600)	(112,000)	(170,500)
Additions to property, plant, equipment									24,200	21,900	0
Total assets at year-end	365,500				1,034,600				365,500	1,034,600	1,220,800
Exploration and Production \| Operating Segments
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									881,200	1,579,100	716,700
Revenues from external customers									3,456,800	4,247,100	2,818,700
Interest and other income (loss)									(5,600)	(9,000)	(10,300)
Interest expense, net of capitalization									(500)	(400)	(200)
Income tax expense (benefit)									237,800	417,300	172,700
Impairment of assets											189,300
Depreciation, depletion and amortization									850,500	763,900	782,100
Accretion of asset retirement obligations									46,000	46,200	46,600
Amortization of undeveloped leases									10,900	13,300	18,900
Deferred and noncurrent income taxes									230,400	398,100	166,400
Additions to property, plant, equipment									890,600	1,041,400	585,300
Total assets at year-end	9,400,200				9,273,600				9,400,200	9,273,600	9,083,300
Exploration and Production \| Operating Segments \| United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									905,100	1,521,900	766,300
Revenues from external customers									2,928,300	3,461,200	2,337,500
Interest and other income (loss)									(3,900)	(6,600)	(11,600)
Interest expense, net of capitalization									(100)	(100)	0
Income tax expense (benefit)									232,700	370,800	183,900
Impairment of assets											0
Depreciation, depletion and amortization									706,000	617,000	616,500
Accretion of asset retirement obligations									37,800	36,500	36,900
Amortization of undeveloped leases									8,100	8,700	11,100
Deferred and noncurrent income taxes									229,600	362,700	176,300
Additions to property, plant, equipment									671,300	838,600	519,500
Total assets at year-end	7,107,000				6,930,600				7,107,000	6,930,600	6,591,600
Exploration and Production \| Operating Segments \| Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									41,600	134,200	(16,100)
Revenues from external customers									517,500	762,900	476,300
Interest and other income (loss)									(1,100)	(1,900)	(1,900)
Interest expense, net of capitalization									(200)	0	0
Income tax expense (benefit)									11,200	43,600	(1,700)
Impairment of assets											171,300
Depreciation, depletion and amortization									142,200	141,500	163,800
Accretion of asset retirement obligations									7,800	9,600	9,700
Amortization of undeveloped leases									100	200	200
Deferred and noncurrent income taxes									7,500	34,800	(1,900)
Additions to property, plant, equipment									206,200	208,500	52,700
Total assets at year-end	2,080,000				2,125,600				2,080,000	2,125,600	2,231,900
Exploration and Production \| Operating Segments \| Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Segment income (loss) - including NCI									(65,500)	(77,000)	(33,500)
Revenues from external customers									11,000	23,000	4,900
Interest and other income (loss)									(600)	(500)	3,200
Interest expense, net of capitalization									(200)	(300)	(200)
Income tax expense (benefit)									(6,100)	2,900	(9,500)
Impairment of assets											18,000
Depreciation, depletion and amortization									2,300	5,400	1,800
Accretion of asset retirement obligations									400	100	0
Amortization of undeveloped leases									2,700	4,400	7,600
Deferred and noncurrent income taxes									(6,700)	600	(8,000)
Additions to property, plant, equipment									13,100	(5,700)	13,100
Total assets at year-end	$ 213,300				$ 217,400				$ 213,300	$ 217,400	$ 259,800

Business Segments - Geographic

Business Segments - Geographic Information on Certain Long-Lived Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 8,225.1	$ 8,228	$ 8,127.9
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	6,555	6,562.8	6,371.4
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	1,497.3	1,499.1	1,566.9
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 172.8	$ 166.1	$ 189.6

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Leases - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Termination period	1 month
Operating leases	$ 5,923	$ 262,669
Offshore drilling rig
Lessee, Lease, Description [Line Items]
Operating leases	$ 4,500	$ 254,000
Lease term	24 months
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	17 years

Leases - Lease Related Expenses

Leases - Lease Related Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Amortization of asset	$ 1,505	$ 5,481
Interest on lease liabilities	221	254
Sublease income	(1,402)	(1,296)
Net lease expense	667,990	487,697
Variable lease expenses primarily related to additional volumes processed at natural gas processing plant	36,700	32,200
Property, plant and equipment
Lessee, Lease, Description [Line Items]
Operating lease cost	204,595	196,829
Short-term lease cost	112,700	125,400
Asset retirement obligations
Lessee, Lease, Description [Line Items]
Operating lease cost	57,442	11,190
Short-term lease cost	57,400	11,200
Lease operating expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	246,721	217,038
Short-term lease cost	78,200	62,800
Transportation, gathering and processing
Lessee, Lease, Description [Line Items]
Operating lease cost	37,797	39,669
Short-term lease cost	29,400	31,500
Selling and general expense
Lessee, Lease, Description [Line Items]
Operating lease cost	9,859	8,003
Short-term lease cost	1,600	700
Other operating expense
Lessee, Lease, Description [Line Items]
Operating lease cost	675	510
Short-term lease cost	300	100
Exploration expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	110,577	10,019
Short-term lease cost	$ 80,300	$ 8,800

Leases - Maturity of Lease Liab

Leases - Maturity of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
2024	$ 244,622
2025	82,596
2026	63,703
2027	62,066
2028	61,229
Remaining	499,501
Total future minimum lease payments	1,013,717
Less imputed interest	(254,032)
Lease obligation	759,685
Finance Leases
2024	1,069
2025	1,069
2026	1,069
2027	1,069
2028	1,069
Remaining	265
Total future minimum lease payments	5,610
Less imputed interest	(1,372)
Present value of lease liabilities	$ 4,238	$ 4,844
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current maturities of long-term debt, finance lease
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Long-term debt, including finance lease obligation
Total
2024	$ 245,691
2025	83,665
2026	64,772
2027	63,135
2028	62,298
Remaining	499,766
Total future minimum lease payments	1,019,327
Less imputed interest	(255,404)
Present value of lease liabilities	$ 763,923

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2023	Dec. 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	5.90%	5.90%
Finance leases	4.70%	4.70%

Leases - Other Lease Informatio

Leases - Other Lease Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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	$ 803
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	5,923	262,669
Offshore drilling rig
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$ 4,500	$ 254,000
Lease term	24 months

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information (Unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl ft³	Dec. 31, 2022 $ / bbl	Dec. 31, 2021 $ / bbl
Reserve Quantities [Line Items]
Future net cash flows annual discount factor, percentage	10%
Equity Method Investee
Reserve Quantities [Line Items]
Reserves attributable to investees accounted for my the equity method \| ft³	0
Net crude oil and condensate revenue
Reserve Quantities [Line Items]
Average production costs per barrel of oil (in dollars per barrel)	78.22	93.67	66.56
Net natural gas revenue
Reserve Quantities [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot)	2.64	6.36	3.60

Supplemental Oil and Gas Info_4

Supplemental Oil and Gas Information (Unaudited) - Summary of Proved Reserves Based on Average Prices (Details) MMcf in Millions, MMBbls in Millions, ft³ in Billions	12 Months Ended
	Dec. 31, 2023 MMBbls ft³	Dec. 31, 2023 ft³ MMBbls	Dec. 31, 2022 MMBbls ft³ MMcf	Dec. 31, 2021 ft³ MMBbls	Dec. 31, 2020 ft³ MMBbls
Proved developed and undeveloped oil reserves:
Proved developed reserves	425.5	425.5	436	419.2	410.8
Proved undeveloped reserves	314	314	279.4	297.7	304.1
Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	715.4		716.9	714.9
Revisions of previous estimates	(13.3)		(23.6)	(52.9)
Improved recovery	0.4		5.3
Extensions and discoveries	112.6		80.1	109.4
Purchases of properties			5	7.4
Sales of properties	(5.2)		(4.4)	(0.7)
Production	(70.4)		(63.9)	(61.1)
Proved developed and undeveloped reserves, ending balance	739.5		715.4	716.9
Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	303.6		291.5	266.5
Revisions of previous estimates	(10.8)		23.4	39.3
Improved recovery	0.4		4.7
Extensions and discoveries	22.5		18.9	14.1
Purchases of properties			4.2	6.4
Sales of properties	(2)		(3.6)
Production	(37.9)		(35.5)	(34.9)
Proved developed and undeveloped reserves, ending balance	275.8		303.6	291.5
Proved developed reserves	186.3	186.3	209	191.5	179.8
Proved undeveloped reserves	89.5	89.5	94.6	99.9	86.7
Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	41.7		38.4	38.2
Revisions of previous estimates	(1.4)		4.4	1.4
Improved recovery			0.2
Extensions and discoveries	2		2.5	2.5
Purchases of properties			0.3	0.1
Sales of properties	(0.6)		(0.2)
Production	(4.1)		(3.9)	(3.8)
Proved developed and undeveloped reserves, ending balance	37.6		41.7	38.4
Proved developed reserves	25.9	25.9	29.7	28.4	28.7
Proved undeveloped reserves	11.7	11.7	12	10	9.5
Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³		2,219.9	2,322.3	2,461
Revisions of previous estimates \| ft³		(6.9)	(309.8)	(562.1)
Improved recovery \| ft³			2.6
Extensions and discoveries \| ft³		528.9	352.4	556.7
Purchases of properties \| ft³			2.9	5.4
Sales of properties		(15.6)	(3,600)	(4.4)
Production \| ft³		(170.1)	(146.9)	(134.2)
Proved developed and undeveloped reserves, ending balance \| ft³		2,556.2	2,219.9	2,322.3
Proved developed reserves \| ft³	1,279.3	1,279.3	1,183.1	1,196	1,213.8
Proved undeveloped reserves \| ft³	1,276.9	1,276.9	1,036.8	1,126.4	1,247.2
MP Gulf of Mexico LLC
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	15.5
Proved developed reserves	12.8	12.8
Proved undeveloped reserves	2.7	2.7
MP Gulf of Mexico LLC \| Net crude oil and condensate revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	14
Proved developed reserves	11.7	11.7
Proved undeveloped reserves	2.3	2.3
MP Gulf of Mexico LLC \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	0.6	1.2
Proved developed reserves	0.5	0.5
Proved undeveloped reserves	0.1	0.1
MP Gulf of Mexico LLC \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance \| ft³		5.3
Proved developed reserves \| ft³	3.8	3.8
Proved undeveloped reserves \| ft³	1.5	1.5
U.S.
Proved developed and undeveloped oil reserves:
Proved developed reserves	223.2	223.2	264.2	241.9	230.3
Proved undeveloped reserves	87.9	87.9	92.8	101.6	98.2
U.S. \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	357		343.4	328.5
Revisions of previous estimates	(13.3)		29	35.6
Improved recovery			5.3
Extensions and discoveries	12.7		20.6	18.2
Purchases of properties			5	1.6
Sales of properties	0		(4.4)	0
Production	(45.3)		(41.9)	(40.4)
Proved developed and undeveloped reserves, ending balance	311.1		357	343.4
U.S. \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	263.6		255	240.6
Revisions of previous estimates	(8.9)		19.9	31.1
Improved recovery	0		4.7
Extensions and discoveries	8.9		16.1	13.5
Purchases of properties			4.2	1.3
Sales of properties	0		(3.6)
Production	(35.6)		(32.7)	(31.5)
Proved developed and undeveloped reserves, ending balance	228		263.6	255
Proved developed reserves	163.7	163.7	194.4	174.9	161.4
Proved undeveloped reserves	64.3	64.3	69.2	80	79.2
U.S. \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	37.6		35.1	34.6
Revisions of previous estimates	(1.2)		3.9	1.4
Improved recovery			0.2
Extensions and discoveries	1.7		1.9	2.4
Purchases of properties			0.3	0.1
Sales of properties	0		(0.2)
Production	(3.8)		(3.6)	(3.4)
Proved developed and undeveloped reserves, ending balance	34.3	71.3	37.6	35.1
Proved developed reserves	24.1	24.1	27.4	25.6	25.5
Proved undeveloped reserves	10.2	10.2	10.2	9.5	9.1
U.S. \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³		334.9	320.3	319.5
Revisions of previous estimates \| ft³		(19)	30.7	18.7
Improved recovery \| ft³			2.6
Extensions and discoveries \| ft³		12.3	15.7	13.5
Purchases of properties \| ft³			2.9	1.5
Sales of properties		0	(3,600)	0
Production \| ft³		(35.1)	(33.7)	(32.8)
Proved developed and undeveloped reserves, ending balance \| ft³		293.1	334.9	320.3
Proved developed reserves \| ft³	212.4	212.4	254.1	248.1	260.2
Proved undeveloped reserves \| ft³	80.7	80.7	80.8	72.2	59.3
Canada
Proved developed and undeveloped oil reserves:
Proved developed reserves	202	202	171.3	176.8	180.5
Proved undeveloped reserves	213.5	213.5	186.5	196	205.9
Canada \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	357.8		372.8	386.4
Revisions of previous estimates	0.2		(52.8)	(89.3)
Improved recovery	0.4		0
Extensions and discoveries	87.3		59.5	91.3
Purchases of properties			0	5.8
Sales of properties	(5.2)		0	(0.7)
Production	(25)		(21.7)	(20.6)
Proved developed and undeveloped reserves, ending balance	415.5		357.8	372.8
Canada \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	39.5		35.9	25.9
Revisions of previous estimates	(1.8)		3.3	7.5
Improved recovery	0.4		0
Extensions and discoveries	1.5		2.8	0.6
Purchases of properties			0	5.2
Sales of properties	(2)		0
Production	(2.2)		(2.5)	(3.3)
Proved developed and undeveloped reserves, ending balance	35.4		39.5	35.9
Proved developed reserves	22.3	22.3	14.2	16	18.4
Proved undeveloped reserves	13.1	13.1	25.3	19.8	7.5
Canada \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	4.1		3.3	3.6
Revisions of previous estimates	(0.2)		0.5	0
Improved recovery			0
Extensions and discoveries	0.3		0.6	0.1
Purchases of properties			0	0
Sales of properties	(0.6)		0
Production	(0.3)		(0.3)	(0.4)
Proved developed and undeveloped reserves, ending balance	3.3	41.9	4.1	3.3
Proved developed reserves	1.8	1.8	2.3	2.8	3.2
Proved undeveloped reserves	1.5	1.5	1.8	0.5	0.4
Canada \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³		1,884.8	2,001.8	2,141.5
Revisions of previous estimates \| ft³		12.1	(340.5)	(581)
Improved recovery \| ft³			0
Extensions and discoveries \| ft³		513.8	336.7	543.2
Purchases of properties \| ft³			0	3.9
Sales of properties		(15.6)	0	(4.4)
Production \| ft³		(135)	(113.2)	(101.4)
Proved developed and undeveloped reserves, ending balance \| ft³		2,260.1	1,884.8	2,001.8
Proved developed reserves \| ft³	1,066.7	1,066.7	928.8	947.7	953.6
Proved undeveloped reserves \| ft³	1,193.4	1,193.4	956	1,054.1	1,187.9
Other
Proved developed and undeveloped oil reserves:
Proved developed reserves	0.3	0.3	0.5	0.6	0
Proved undeveloped reserves	12.6	12.6	0.1	0.1	0
Other \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	0.6		0.7	0
Revisions of previous estimates	(0.2)		0.2	0.8
Improved recovery	0		0
Extensions and discoveries	12.6		0	0
Purchases of properties			0	0
Sales of properties	0		0	0
Production	(0.1)		(0.3)	(0.1)
Proved developed and undeveloped reserves, ending balance	12.9		0.6	0.7
Other \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	0.5		0.6	0
Revisions of previous estimates	(0.1)		0.2	0.7
Improved recovery	0		0
Extensions and discoveries	12.1		0	0
Purchases of properties			0	0
Sales of properties	0		0
Production	(0.1)		(0.3)	(0.1)
Proved developed and undeveloped reserves, ending balance	12.4		0.5	0.6
Proved developed reserves	0.3	0.3	0.4	0.5	0
Proved undeveloped reserves	12.1	12.1	0.1	0.1	0
Other \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	0		0	0
Revisions of previous estimates	0		0	0
Improved recovery			0
Extensions and discoveries	0		0	0
Purchases of properties			0	0
Sales of properties	0		0
Production	0		0	0
Proved developed and undeveloped reserves, ending balance	0	2.8	0	0
Proved developed reserves	0	0	0	0	0
Proved undeveloped reserves	0	0	0	0	0
Other \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³		0.2	0.2	0
Revisions of previous estimates \| ft³		0	0	0.2
Improved recovery \| ft³			0
Extensions and discoveries \| ft³		2.8	0	0
Purchases of properties \| ft³			0	0
Sales of properties		0	0	0
Production \| ft³		0	0	0
Proved developed and undeveloped reserves, ending balance \| ft³		3	0.2	0.2
Proved developed reserves \| ft³	0.2	0.2	0.2	0.2	0
Proved undeveloped reserves \| ft³	2.8	2.8	0	0	0

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property acquisition costs
Unproved	$ 8.5	$ 1.8	$ 8.8
Proved	27.1	128.5
Proved			0.5
Total acquisition costs	35.6	130.3	8.3
Exploration costs	198.1	113.3	62.2
Development costs	880.8	917.7	619.3
Total costs incurred	1,114.5	1,161.3	689.8
Charged to expense
Dry hole expense	169.8	82.1	17.3
Geophysical and other costs	54.1	37.7	32.8
Total charged to expense	223.9	119.8	50.1
Property additions	890.6	1,041.5	$ 639.7
Terra Nova
Charged to expense
Additional percentage acquired through commercial settlement			7.525%
U.S.
Property acquisition costs
Unproved	0	1.8	$ 8.8
Proved	12.8	128.5	19.9
Total acquisition costs	12.8	130.3	28.7
Exploration costs	157.8	42.2	31.7
Development costs	667.2	704.9	513.2
Total costs incurred	837.8	877.4	573.6
Charged to expense
Dry hole expense	153.1	23	17.3
Geophysical and other costs	13.4	15.8	13.1
Total charged to expense	166.5	38.8	30.4
Property additions	671.3	838.6	543.2
Canada
Property acquisition costs
Unproved	0	0	0
Proved	0	0
Proved			20.4
Total acquisition costs	0	0	20.4
Exploration costs	0.4	0.8	0.4
Development costs	206.2	208.5	102.4
Total costs incurred	206.6	209.3	82.4
Charged to expense
Dry hole expense	0	0	0
Geophysical and other costs	0.4	0.8	0.4
Total charged to expense	0.4	0.8	0.4
Property additions	206.2	208.5	82
Other
Property acquisition costs
Unproved	8.5	0	0
Proved	14.3	0	0
Total acquisition costs	22.8	0	0
Exploration costs	39.9	70.3	30.1
Development costs	7.4	4.3	3.7
Total costs incurred	70.1	74.6	33.8
Charged to expense
Dry hole expense	16.7	59.1	0
Geophysical and other costs	40.3	21.1	19.3
Total charged to expense	57	80.2	19.3
Property additions	$ 13.1	$ (5.6)	$ 14.5

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues
Revenues	$ 3,448,900	$ 4,220,200	$ 2,801,200
Other operating revenues	7,900	26,700	17,500
Total revenues	3,456,800	4,246,900	2,818,700
Costs and expenses
Lease operating expenses	784,400	679,300	539,500
Severance and ad valorem taxes	42,800	57,000	41,200
Transportation, gathering and processing	232,985	212,711	187,028
Costs of purchased natural gas	51,682	171,991	0
Exploration costs charged to expense	223,900	119,800	50,100
Undeveloped lease amortization	10,900	13,300	18,900
Depreciation, depletion and amortization	850,500	763,900	782,100
Accretion of asset retirement obligations	46,000	46,200	46,600
Impairment of assets			189,300
Selling and general expenses	37,700	44,500	43,600
Other expenses (benefits)	56,900	141,800	31,000
Total costs and expenses	2,337,800	2,250,500	1,929,300
Results of operations before taxes	1,119,000	1,996,400	889,400
Income tax expense (benefit)	237,800	417,300	172,700
Results of operations	881,200	1,579,100	716,700
Crude Oil and Natural Gas Liquids
Revenues
Revenues	3,005,800	3,500,600	2,433,500
Natural Gas
Revenues
Revenues	370,900	537,900	367,700
Sales of purchased natural gas
Revenues
Revenues	72,200	181,700
U.S.
Revenues
Revenues	2,921,800	3,435,800	2,321,500
Other operating revenues	6,500	25,400	16,000
Total revenues	2,928,300	3,461,200	2,337,500
Costs and expenses
Lease operating expenses	630,700	522,700	406,400
Severance and ad valorem taxes	41,400	55,700	39,600
Transportation, gathering and processing	157,000	142,200	126,500
Costs of purchased natural gas	0	200
Exploration costs charged to expense	166,500	38,800	30,400
Undeveloped lease amortization	8,100	8,700	11,100
Depreciation, depletion and amortization	706,000	617,000	616,500
Accretion of asset retirement obligations	37,800	36,500	36,900
Impairment of assets			0
Selling and general expenses	11,800	20,400	20,500
Other expenses (benefits)	31,200	126,300	99,400
Total costs and expenses	1,790,500	1,568,500	1,387,300
Results of operations before taxes	1,137,800	1,892,700	950,200
Income tax expense (benefit)	232,700	370,800	183,900
Results of operations	905,100	1,521,900	766,300
U.S. \| Crude Oil and Natural Gas Liquids
Revenues
Revenues	2,829,100	3,210,300	2,199,700
U.S. \| Natural Gas
Revenues
Revenues	92,700	225,300	121,800
U.S. \| Sales of purchased natural gas
Revenues
Revenues	0	200
Canada \| Conventional gas
Revenues
Revenues	516,100	761,600	474,800
Other operating revenues	1,400	1,300	1,500
Total revenues	517,500	762,900	476,300
Costs and expenses
Lease operating expenses	151,800	155,100	136,300
Severance and ad valorem taxes	1,400	1,300	1,600
Transportation, gathering and processing	76,000	70,500	60,500
Costs of purchased natural gas	51,700	171,800
Exploration costs charged to expense	400	800	400
Undeveloped lease amortization	100	200	200
Depreciation, depletion and amortization	142,200	141,500	163,800
Accretion of asset retirement obligations	7,800	9,600	9,700
Impairment of assets			171,300
Selling and general expenses	16,500	21,900	16,500
Other expenses (benefits)	16,800	12,400	(66,200)
Total costs and expenses	464,700	585,100	494,100
Results of operations before taxes	52,800	177,800	(17,800)
Income tax expense (benefit)	11,200	43,600	(1,700)
Results of operations	41,600	134,200	(16,100)
Canada \| Crude Oil and Natural Gas Liquids \| Conventional gas
Revenues
Revenues	165,700	267,500	228,900
Canada \| Natural Gas \| Conventional gas
Revenues
Revenues	278,200	312,600	245,900
Canada \| Sales of purchased natural gas \| Conventional gas
Revenues
Revenues	72,200	181,500
Other
Revenues
Revenues	11,000	22,800	4,900
Other operating revenues	0	0	0
Total revenues	11,000	22,800	4,900
Costs and expenses
Lease operating expenses	1,900	1,500
Lease operating expenses			(3,200)
Severance and ad valorem taxes	0	0	0
Transportation, gathering and processing	0	0	0
Costs of purchased natural gas	0	0
Exploration costs charged to expense	57,000	80,200	19,300
Undeveloped lease amortization	2,700	4,400	7,600
Depreciation, depletion and amortization	2,300	5,400	1,800
Accretion of asset retirement obligations	400	100	0
Impairment of assets			18,000
Selling and general expenses	9,400	2,200	6,600
Other expenses (benefits)	8,900	3,100	(2,200)
Total costs and expenses	82,600	96,900	47,900
Results of operations before taxes	(71,600)	(74,100)	(43,000)
Income tax expense (benefit)	(6,100)	2,900	(9,500)
Results of operations	(65,500)	(77,000)	(33,500)
Other \| Crude Oil and Natural Gas Liquids
Revenues
Revenues	11,000	22,800	4,900
Other \| Natural Gas
Revenues
Revenues	0	0	$ 0
Other \| Sales of purchased natural gas
Revenues
Revenues	$ 0	$ 0

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information (Unaudited) - Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 27,944.5	$ 39,697.3	$ 25,696.7
Future development costs	(2,759.2)	(2,238.3)	(1,686.8)
Future production costs	(12,368.5)	(12,508.5)	(10,675.4)
Future income taxes	(1,813.4)	(4,400.9)	(1,592.8)
Future net cash flows	11,003.4	20,549.6	11,741.6
10% annual discount for estimated timing of cash flows	(4,150)	(8,736.4)	(4,442.7)
Standardized measure of discounted future net cash flows	6,853.4	11,813.2	7,299	$ 2,618.6
U.S.
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	18,927.6	27,277.9	18,449.1
Future development costs	(1,685.3)	(1,594.5)	(1,164.3)
Future production costs	(7,856.2)	(8,297.4)	(7,140.6)
Future income taxes	(1,057.5)	(2,606.8)	(1,024.4)
Future net cash flows	8,328.6	14,779.2	9,119.9
10% annual discount for estimated timing of cash flows	(2,840.6)	(5,709.8)	(3,264.9)
Standardized measure of discounted future net cash flows	5,488	9,069.4	5,855.1
Canada
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	8,012.7	12,360.2	7,203.5
Future development costs	(769.6)	(642.4)	(521.1)
Future production costs	(4,223.6)	(4,199)	(3,525.8)
Future income taxes	(634.6)	(1,788.7)	(565.4)
Future net cash flows	2,384.9	5,730.1	2,591.3
10% annual discount for estimated timing of cash flows	(1,056.9)	(3,015.6)	(1,169.3)
Standardized measure of discounted future net cash flows	1,328	2,714.5	1,422
Other
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	1,004.2	59.2	44
Future development costs	(304.3)	(1.4)	(1.5)
Future production costs	(288.7)	(12.1)	(9.1)
Future income taxes	(121.3)	(5.4)	(3)
Future net cash flows	289.9	40.3	30.4
10% annual discount for estimated timing of cash flows	(252.5)	(11)	(8.5)
Standardized measure of discounted future net cash flows	$ 37.4	$ 29.3	$ 21.9

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information (Unaudited) - Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl	Dec. 31, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($) $ / bbl
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Net changes in prices and production costs	$ (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, beginning balance	11,813.2	7,299	2,618.6
Standardized measure, ending balance	$ 6,853.4	$ 11,813.2	$ 7,299
Net crude oil and condensate revenue
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Average production costs per barrel of oil (in dollars per barrel) \| $ / bbl	78.22	93.67	66.56
Net natural gas revenue
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot) \| $ / bbl	2.64	6.36	3.60

Supplemental Oil and Gas Info_9

Supplemental Oil and Gas Information (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	$ 400.1	$ 648.9
Proved oil and natural gas properties	20,738.1	19,792.6
Gross capitalized costs	21,138.2	20,441.5
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(122.7)	(132.5)
Proved oil and natural gas properties	(12,829.4)	(12,122.9)
Net capitalized costs	8,186.1	8,186.1
U.S.
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	337.3	494.6
Proved oil and natural gas properties	15,868.4	15,051.9
Gross capitalized costs	16,205.7	15,546.5
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(105.3)	(117.8)
Proved oil and natural gas properties	(9,552.9)	(8,873.6)
Net capitalized costs	6,547.5	6,555.1
Canada
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	13.1	19.2
Proved oil and natural gas properties	4,716	4,684.8
Gross capitalized costs	4,729.1	4,704
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	0	0
Proved oil and natural gas properties	(3,233.7)	(3,208)
Net capitalized costs	1,495.4	1,496
Other
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	49.7	135.1
Proved oil and natural gas properties	153.7	55.9
Gross capitalized costs	203.4	191
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(17.4)	(14.7)
Proved oil and natural gas properties	(42.8)	(41.3)
Net capitalized costs	$ 143.2	$ 135

Supplemental Quarterly Inform_3

Supplemental Quarterly Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Interim Reporting [Line Items]
Revenue from contracts with customers	$ 842,200	$ 953,800	$ 812,900	$ 840,000	$ 986,100	$ 1,166,400	$ 1,196,200	$ 871,400	$ 3,448,854	$ 4,220,140	$ 2,801,215
Income (loss) from continuing operations before income taxes	169,500	356,300	127,300	267,900	282,700	734,000	515,500	(81,900)	921,069	1,450,261	42,891
Income (loss) from continuing operations	140,500	278,200	92,500	214,000	220,800	574,500	410,400	(64,900)	725,148	1,140,797	48,753
Net income including noncontrolling interest	139,700	277,800	91,900	214,300	220,600	574,100	409,500	(65,500)	723,681	1,138,719	47,528
Net income (loss) attributable to Murphy	$ 116,400	$ 255,300	$ 98,300	$ 191,600	$ 199,400	$ 528,300	$ 350,600	$ (113,300)	$ 661,559	$ 965,047	$ (73,664)
Income (loss) from continuing operations per common share
Basic (in USD per share)	$ 0.76	$ 1.64	$ 0.63	$ 1.23	$ 1.28	$ 3.40	$ 2.27	$ (0.73)	$ 4.27	$ 6.23	$ (0.47)
Diluted (in USD per share)	0.75	1.63	0.62	1.22	1.26	3.36	2.24	(0.73)	4.23	6.14	(0.47)
Net income (loss) per common share
Basic (in USD per share)	0.76	1.64	0.63	1.23	1.28	3.40	2.26	(0.73)	4.26	6.22	(0.48)
Diluted (in USD per share)	0.75	1.63	0.62	1.22	1.26	3.36	2.23	(0.73)	4.22	6.13	(0.48)
Cash dividend per Common share (in USD per share)	$ 0.275	$ 0.275	$ 0.275	$ 0.275	$ 0.250	$ 0.250	$ 0.175	$ 0.150	$ 1.100	$ 0.825	$ 0.500
Minimum
Interim Reporting [Line Items]
Income (loss) from continuing operations before income taxes									$ 921,000
Maximum
Interim Reporting [Line Items]
Income (loss) from continuing operations									$ 725,200

Schedule II - Valuation Accou_2

Schedule II - Valuation Accounts and Reserves (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Allowance for doubtful accounts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning balance	$ 1.6	$ 1.6	$ 1.6
Charged to Expense	0	0	0
Deductions	0	0	0
Other	0	0	0
Ending balance	1.6	1.6	1.6
Deferred tax asset valuation allowance
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning balance	136	111.2	106.4
Charged to Expense	10.9	24.8	4.8
Deductions	0	0	0
Other	0	0	0
Ending balance	$ 146.9	$ 136	$ 111.2