Murphy Oil (MUR) 10-K 27 Feb 25 2024 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2024	Jan. 31, 2025	Jun. 28, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
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			$ 4,465,018,220
Entity Common Stock, Shares Outstanding		145,855,183
Documents Incorporated by Reference	Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 14, 2025 have been incorporated by reference in Part III herein.
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Entity Central Index Key	0000717423
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
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, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents		$ 423,569	$ 317,074
Accounts receivable, net		272,530	343,992
Inventories		54,858	54,454
Prepaid expenses		34,322	36,674
Total current assets		785,279	752,194
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $13,811,539 in 2024 and $13,135,385 in 2023		8,054,653	8,225,197
Operating lease assets		777,536	745,185
Deferred income taxes		0	435
Deferred charges and other assets		50,011	43,686
Total assets		9,667,479	9,766,697
Current liabilities
Current maturities of long-term debt, finance lease		871	723
Accounts payable		472,165	446,891
Income taxes payable		19,003	21,007
Other taxes payable		31,685	29,339
Operating lease liabilities		253,208	207,840
Other accrued liabilities		117,802	130,033
Current asset retirement obligations	[1]	48,080	10,712
Total current liabilities		942,814	846,545
Long-term debt, including finance lease obligation		1,274,502	1,328,352
Asset retirement obligations		960,804	904,051
Deferred credits and other liabilities		274,345	309,605
Non-current operating lease liabilities		537,381	551,845
Deferred income taxes		335,790	276,646
Total liabilities		4,325,636	4,217,044
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 2024 and 195,100,628 shares in 2023		195,101	195,101
Capital in excess of par value		848,950	880,297
Retained earnings		6,773,289	6,546,079
Accumulated other comprehensive loss		(628,072)	(521,117)
Treasury stock		(1,995,018)	(1,737,566)
Murphy Shareholders' Equity		5,194,250	5,362,794
Noncontrolling interest		147,593	186,859
Total equity		5,341,843	5,549,653
Total liabilities and equity		$ 9,667,479	$ 9,766,697
[1] The prior-period amount has been reclassified to conform to the current period presentation.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Accumulated depreciation, depletion and amortization	$ 13,811,539	$ 13,135,385
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 ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues and other income
Total revenue from sales to customers	$ 3,018,598,000	$ 3,448,854,000	$ 4,220,140,000
(Loss) on derivative instruments	(1,707,000)	0	(320,410,000)
Gain on sale of assets and other operating income	11,583,000	11,293,000	32,932,000
Total revenues and other income	3,028,474,000	3,460,147,000	3,932,662,000
Costs and expenses
Lease operating expenses	936,960,000	784,391,000	679,342,000
Severance and ad valorem taxes	39,162,000	42,787,000	57,012,000
Transportation, gathering and processing	210,827,000	232,985,000	212,711,000
Costs of purchased natural gas	3,147,000	51,682,000	171,991,000
Exploration expenses, including undeveloped lease amortization	133,538,000	234,776,000	133,197,000
Selling and general expenses	110,085,000	117,306,000	131,121,000
Depreciation, depletion and amortization	865,753,000	861,602,000	776,817,000
Accretion of asset retirement obligations	52,511,000	46,059,000	46,243,000
Impairment of assets	62,909,000	0	0
Other operating expense	10,989,000	46,530,000	137,518,000
Total costs and expenses	2,425,881,000	2,418,118,000	2,345,952,000
Operating income from continuing operations	602,593,000	1,042,029,000	1,586,710,000
Other income (loss)
Other income (loss)	70,902,000	(8,587,000)	14,310,000
Interest expense, net	(105,926,000)	(112,373,000)	(150,759,000)
Total other loss	(35,024,000)	(120,960,000)	(136,449,000)
Income from continuing operations before income taxes	567,569,000	921,069,000	1,450,261,000
Income tax expense	78,272,000	195,921,000	309,464,000
Income from continuing operations	489,297,000	725,148,000	1,140,797,000
Loss from discontinued operations, net of income taxes	(2,812,000)	(1,467,000)	(2,078,000)
Net income including noncontrolling interest	486,485,000	723,681,000	1,138,719,000
Less: Net income attributable to noncontrolling interest	79,314,000	62,122,000	173,672,000
NET INCOME ATTRIBUTABLE TO MURPHY	$ 407,171,000	$ 661,559,000	$ 965,047,000
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations (in USD per share)	$ 2.73	$ 4.27	$ 6.23
Discontinued operations (in USD per share)	(0.02)	(0.01)	(0.01)
Net income (in USD per share)	2.71	4.26	6.22
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations (in USD per share)	2.72	4.23	6.14
Discontinued operations (in USD per share)	(0.02)	(0.01)	(0.01)
Net income (in USD per share)	2.70	4.22	6.13
Cash dividends per Common share (in USD per share)	$ 1.200	$ 1.100	$ 0.825
Average common shares outstanding (thousands)
Basic (in shares)	150,011,458	155,233,560	155,276,533
Diluted (in shares)	151,027,352	156,646,429	157,474,838
Revenue from production
Revenues and other income
Total revenue from sales to customers	$ 3,014,856,000	$ 3,376,639,000	$ 4,038,451,000
Sales of purchased natural gas
Revenues and other income
Total revenue from sales to customers	$ 3,742,000	$ 72,215,000	$ 181,689,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interest	$ 486,485	$ 723,681	$ 1,138,719
Other comprehensive income (loss), net of tax
Net (loss) gain from foreign currency translation	(134,692)	36,598	(106,335)
Retirement and postretirement benefit plans	27,737	(23,029)	99,360
Other comprehensive income (loss)	(106,955)	13,569	(6,975)
Comprehensive income including noncontrolling interest	379,530	737,250	1,131,744
Less: Comprehensive income attributable to noncontrolling interest	79,314	62,122	173,672
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY	$ 300,216	$ 675,128	$ 958,072

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Activities
Net income including noncontrolling interest	$ 486,485,000	$ 723,681,000	$ 1,138,719,000
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	865,753,000	861,602,000	776,817,000
Unsuccessful exploration well costs and previously suspended exploration costs	73,201,000	169,795,000	82,085,000
Deferred income tax expense	72,434,000	179,823,000	286,079,000
Impairment of assets	62,909,000	0	0
Accretion of asset retirement obligations	52,511,000	46,059,000	46,243,000
Long-term non-cash compensation	45,057,000	61,953,000	89,246,000
Amortization of undeveloped leases	9,587,000	10,925,000	13,300,000
Loss from discontinued operations	2,812,000	1,467,000	2,078,000
Mark-to-market loss (gain) on derivative instruments	1,707,000	0	(214,788,000)
Contingent consideration payment	0	(139,574,000)	0
Mark-to-market loss on contingent consideration	0	7,113,000	78,285,000
Gain from sale of assets	0	0	(17,899,000)
Other operating activities, net	(18,349,000)	(74,728,000)	(34,193,000)
Net decrease (increase) in non-cash working capital	74,883,000	(99,361,000)	(65,728,000)
Net cash provided by continuing operations activities	1,728,990,000	1,748,755,000	2,180,244,000
Investing Activities
Property additions and dry hole costs	(908,164,000)	(1,066,015,000)	(985,461,000)
Acquisition of oil and natural gas properties	0	(35,578,000)	(128,538,000)
Proceeds from sales of property, plant and equipment	0	102,913,000	4,528,000
Net cash required by investing activities	(908,164,000)	(998,680,000)	(1,109,471,000)
Financing Activities
Retirement of debt	(650,112,000)	(498,175,000)	(647,707,000)
Early redemption of debt cost	(15,700,000)	0	(8,295,000)
Debt issuance	600,000,000	0	0
Debt issuance cost	(10,145,000)	0	0
Borrowings on revolving credit facility	350,000,000	600,000,000	400,000,000
Repayment of revolving credit facility	(350,000,000)	(600,000,000)	(400,000,000)
Issue costs of revolving credit facility	(14,718,000)	(20,000)	(14,353,000)
Repurchase of common stock	(301,350,000)	(150,022,000)	0
Cash dividends paid	(179,961,000)	(170,978,000)	(128,219,000)
Distributions to noncontrolling interest	(118,580,000)	(29,382,000)	(183,038,000)
Withholding tax on stock-based incentive awards	(25,310,000)	(14,276,000)	(17,631,000)
Finance lease obligation payments	(665,000)	(622,000)	(636,000)
Contingent consideration payment	0	(60,243,000)	(81,742,000)
Net cash required by financing activities	(716,541,000)	(923,718,000)	(1,081,621,000)
Net cash required by discontinued operations	0	0	(14,500,000)
Effect of exchange rate changes on cash and cash equivalents	2,210,000	(1,246,000)	(3,873,000)
Net increase (decrease) in cash and cash equivalents	106,495,000	(174,889,000)	(29,221,000)
Cash and cash equivalents at beginning of period	317,074,000	491,963,000	521,184,000
Cash and cash equivalents at end of period	$ 423,569,000	$ 317,074,000	$ 491,963,000

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands		Total	Murphy Shareholders’ Equity	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, 2021					$ 926,698	$ 5,218,670	$ (527,711)	$ (1,655,447)	$ 163,485
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock transactions and other	[1]				(58,362)
Share-based compensation					25,242
Net income attributable to Murphy		$ 965,047				965,047			173,672
Cash dividends paid						(128,219)
Foreign currency translation (loss) gain, net of income taxes		(106,335)					(106,335)
Other comprehensive income (loss)		(6,975)
Retirement and postretirement benefit plans, net of income taxes							99,360
Repurchase of common stock								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	$ 195,101	893,578	6,055,498	(534,686)	(1,614,717)	154,119
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock transactions and other	[1]				(42,667)
Share-based compensation					29,386
Net income attributable to Murphy		661,559				661,559			62,122
Cash dividends paid						(170,978)
Foreign currency translation (loss) gain, net of income taxes		36,598					36,598
Other comprehensive income (loss)		13,569					13,569
Retirement and postretirement benefit plans, net of income taxes							(23,029)
Repurchase of common stock								(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	195,101	880,297	6,546,079	(521,117)	(1,737,566)	186,859
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock transactions and other	[1]				(70,539)
Share-based compensation					39,192
Net income attributable to Murphy		407,171				407,171			79,314
Cash dividends paid						(179,961)
Foreign currency translation (loss) gain, net of income taxes		(134,692)					(134,692)
Other comprehensive income (loss)		(106,955)					(106,955)
Retirement and postretirement benefit plans, net of income taxes							27,737
Repurchase of common stock		(300,000)						(302,681)
Awarded restricted stock, net of forfeitures								45,229
Distributions to noncontrolling interest owners									(118,580)
Balance at end of year at Dec. 31, 2024		$ 5,341,843	$ 5,194,250	$ 195,101	$ 848,950	$ 6,773,289	$ (628,072)	$ (1,995,018)	$ 147,593
[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, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Cumulative preferred stock, shares issued (in shares)	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)	49,255,504	42,351,986	39,633,309

Significant Accounting Polices

Significant Accounting Polices	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Significant Accounting Polices	Note A – Significant Accounting Policies NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the U.S. and Canada and conducts oil and natural gas exploration activities worldwide. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries and are presented in conformity with GAAP. 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. 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 and NGLs 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, 2024 and 2023, 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, 2024 and 2023, 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 including 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 assessed when there is an indication 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 its fair value. See Note D for further discussion of impairment charges. The Company records a liability for 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, plugging and abandoning wells and restoring sites 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 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. 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 arising from 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 it may 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 risk management objectives and strategy. 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) with market based conditions, and expense is recognized over the three-year vesting period. The fair value of PSUs with performance-based conditions and time-based restricted stock units (RSUs) is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two 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 .

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2024
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 Reportable Segment Disclosures. In November 2023, the FASB issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . 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 Company adopted this standard in the fourth quarter of 2024. The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note S . Recent Accounting Pronouncements Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. Income Tax Disclosures. In December 2023, the FASB issued 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. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2024
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 NGLs (collectively referred to as oil and natural gas) in select basins around the world. 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, natural gas and NGLs. For operated oil and natural gas production where a 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 U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. 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. The Company also purchases natural gas in Canada to meet certain sales commitments. 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 years presented were as follows. Years Ended December 31, (Thousands of dollars) 2024 2023 2022 Net crude oil and condensate revenue United States - Onshore $ 586,584 $ 676,139 $ 856,219 United States - Offshore 1 1,777,723 2,072,353 2,229,658 Canada - Onshore 70,855 78,088 131,400 Canada - Offshore 193,961 78,650 117,747 Other 6,537 11,022 22,824 Total crude oil and condensate revenue 2,635,660 2,916,252 3,357,848 Net natural gas liquids revenue United States - Onshore 32,853 33,178 64,015 United States - Offshore 1 38,858 47,434 60,424 Canada - Onshore 7,454 8,914 18,338 Total natural gas liquids revenue 79,165 89,526 142,777 Net natural gas revenue United States - Onshore 17,443 21,346 64,037 United States - Offshore 1 50,329 71,332 161,160 Canada - Onshore 232,259 278,183 312,629 Total natural gas revenue 300,031 370,861 537,826 Revenue from production 3,014,856 3,376,639 4,038,451 Sales of purchased natural gas 2 United States - Offshore — — 204 Canada - Onshore 3,742 72,215 181,485 Total sales of purchased natural gas 3,742 72,215 181,689 Total revenue from sales to customers 3,018,598 3,448,854 4,220,140 (Loss) on derivative instruments (1,707) — (320,410) Gain on sale of assets and other operating income 11,583 11,293 32,932 Total revenues and other income $ 3,028,474 $ 3,460,147 $ 3,932,662 1 Includes revenue attributable to noncontrolling interest in MP GOM. 2 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, 2024 and 2023, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $178.3 million and $193.7 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, 2024, 2023 or 2022. The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer. Performance 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, 2024, 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, 2024 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGLs Q2 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 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 Canada Natural Gas Q4 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCFD Canada NGLs Q2 2025 Contracts to sell NGLs at CAD index pricing As produced The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 21,716,358 $ 8,021,620 2 $ 21,228,490 $ 8,201,475 2 Corporate and other 149,834 33,033 132,092 23,722 Property, plant and equipment $ 21,866,192 $ 8,054,653 $ 21,360,582 $ 8,225,197 ¹ Includes unproved mineral rights as follows: $ 283,015 $ 151,341 $ 351,000 $ 228,329 2 Includes $13,335 in 2024 and $15,356 in 2023 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% 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 ARO liabilities 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 its working interests in Block CA-2 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 non-operated 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 non-operated Kodiak field for a purchase price of $50.0 million, net of closing adjustments. Impairments In 2024, the Company recorded a pretax impairment charge of $62.9 million. In the first quarter of 2024, the Company recorded an impairment charge of $34.5 million related to the Calliope field, and in the fourth quarter of 2024, the Company recorded an impairment charge of $28.4 million related to the Nearly Headless Nick field. Both of the impairments were the result of operational issues that led to reserve reductions. There were no impairments recognized in 2023 and 2022. The following table reflects the recognized before tax impairments for each of the three years presented. (Thousands of dollars) 2024 2023 2022 United States - Offshore $ 62,909 $ — $ — $ 62,909 $ — $ — 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, 2024, 2023 and 2022, the Company had total capitalized drilling costs pending the determination of proved reserves of $72.1 million, $49.1 million and $171.9 million, respectively. The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented. ( Thousands of dollars ) 2024 2023 2022 Beginning balance at January 1 $ 49,118 $ 171,860 $ 179,481 Additions pending the determination of proved reserves 49,408 48 33,440 Reclassifications to proved properties based on the determination of proved reserves — (82,185) — Divestment — — (7,915) Capitalized exploration well costs charged to expense (26,471) (40,605) (33,146) Ending balance at December 31 $ 72,055 $ 49,118 $ 171,860 Capital additions of $49.4 million, for the year ended December 31, 2024, are mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam. Capitalized well costs charged to dry hole expense of $26.5 million, for the year ended December 31, 2024, related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well. The preceding table excludes well costs of $46.7 million and $129.2 million incurred and expensed directly to dry hole during the year ended December 31, 2024 and 2023, respectively. In 2024, these costs primarily include $27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $26.1 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America. In 2023, the amount primarily includes $82.0 million for the Chinook #7 (Walker Ridge 425) and $47.2 million for the non-operated Oso #1 (Atwater Valley 138) exploration wells in the Gulf of America. The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well. 2024 2023 2022 ( Thousands of dollars ) Amount No. of Amount No. of Amount No. of Aging of capitalized well costs Zero to one year $ 49,790 5 $ — — $ 15,527 2 One to two years — — — — 13,307 2 Two to three years — — 2,698 1 — — Three years or more 22,265 3 46,420 3 143,026 5 $ 72,055 8 $ 49,118 4 $ 171,860 9 Of the $22.3 million of exploratory well costs capitalized more than one year at December 31, 2024, $15.1 million was in Vietnam, $4.4 million was in Canada and $2.7 million was 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
	Dec. 31, 2024
Inventory Disclosure [Abstract]
Inventories	Note E – Inventories Inventories consisted of the following for the respective periods presented: December 31, ( Thousands of dollars ) 2024 2023 Unsold crude oil $ 18,745 $ 10,304 Materials and supplies 36,113 44,150 Inventories $ 54,858 $ 54,454

Financing Arrangements and Debt

Financing Arrangements and Debt	12 Months Ended
	Dec. 31, 2024
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) 2024 2023 Notes payable 5.875% notes, due December 2027 $ 78,899 $ 443,249 6.375% notes, due July 2028 148,590 372,226 7.05% notes, due May 2029 117,582 179,708 6.00% notes, due October 2032 600,000 — 5.875% notes, due December 2042 ¹ 339,761 339,761 Total notes payable 1,284,832 1,334,944 Unamortized debt issuance cost and discount on notes payable (14,336) (10,107) Total notes payable, net of unamortized discount 1,270,496 1,324,837 Finance lease obligations, due through November 2034 4,877 4,238 Total debt including current maturities 1,275,373 1,329,075 Current maturities (871) (723) Total long-term debt $ 1,274,502 $ 1,328,352 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 principal repayable over each of the next five years and thereafter are as follows: nil in 2025, nil in 2026, $78.9 million in 2027, $148.6 million in 2028, $117.6 million in 2029 and $939.8 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, 2027. Revolving Credit Facility During the fourth quarter of 2024, the Company entered into a credit agreement governing a $1.35 billion senior unsecured guaranteed RCF with a maturity date of October 7, 2029. The RCF extends the borrowing term and increases the borrowing capacity of the previous RCF. 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 3.25x 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 Wall Street Journal prime rate in effect on such day, (b) the New York Federal Reserve Bank 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 Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $14.7 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, 2024, the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF. At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68%. At December 31, 2024, the Company was in compliance with all covenants related to the RCF. Debt Offering On October 3, 2024, the Company closed the public offering of $600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000% per annum and mature on October 1, 2032. The Company has incurred transaction costs of $10.1 million on the issuance of these new notes. The Company will pay interest semi-annually on April 1 and October 1 of each year, beginning April 1, 2025. The proceeds of the $600.0 million notes were used to fund the repurchase and repayment of debt during the fourth quarter of 2024 to achieve a debt-neutral transaction. Debt Extinguishment In December 2024, the Company redeemed $79.0 million of the 2027 Notes. The total cost of the debt extinguishment of $1.2 million, consisting of cash costs of $0.8 million and non-cash costs of $0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. In October 2024, the Company tendered an aggregate $521.1 million of its notes, comprised of: $258.8 million of the 2027 Notes, $200.2 million of the 2028 Notes and $62.1 million of the 2029 Notes. The total cost of the debt extinguishment of $18.2 million, consisting of cash costs of $14.9 million and non-cash costs of $3.3 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. In May 2024, the Company paid a total of $50.5 million to complete the open market repurchases of $26.5 million aggregate principal of its 2027 Notes and $23.5 million aggregate principal of its 2028 Notes. The total cost of debt extinguishment of $0.9 million, consisting of cash costs of $0.5 million and non-cash costs of $0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. In November 2023, the Company tendered a total of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $250.0 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 the 2025 Notes. The non-cash costs of debt extinguishment of $0.9 million were included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note G – Asset Retirement Obligations The ARO 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) 2024 2023 Balance at beginning of year $ 914,763 $ 911,653 Accretion 52,511 46,059 Liabilities incurred 25,619 20,628 Revisions of previous estimates 29,279 29,056 Liabilities settled (1,898) (95,637) Changes due to translation of foreign currencies (11,390) 3,004 Balance at end of period 1,008,884 914,763 Current portion of liability (48,080) (10,712) Non-current portion of liability $ 960,804 $ 904,051 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
	Dec. 31, 2024
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 ) 2024 2023 2022 Income (loss) from continuing operations before income taxes United States $ 468,202 $ 901,761 $ 1,306,200 Foreign 99,367 19,308 144,061 Total $ 567,569 $ 921,069 $ 1,450,261 Income tax expense (benefit) U.S. Federal – Current $ — $ — $ — – Deferred 55,377 170,115 234,749 Total U.S. Federal 55,377 170,115 234,749 State (4,488) 6,622 9,010 Foreign – Current 4,685 13,182 18,134 – Deferred 22,698 6,002 47,571 Total Foreign 27,383 19,184 65,705 Total $ 78,272 $ 195,921 $ 309,464 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 ) 2024 2023 2022 Income tax expense based on the U.S. statutory tax rate $ 119,190 $ 193,424 $ 304,555 Foreign income subject to foreign tax rates different than the U.S. statutory rate 12,119 7,597 10,823 State income taxes, net of federal benefit (3,568) 4,725 7,118 U.S. tax benefit on certain foreign upstream investments (33,677) — — Change in deferred tax asset valuation allowance related to other foreign exploration expenditures 2,636 10,853 24,748 Tax effect on income attributable to noncontrolling interest (16,656) (13,046) (36,471) Other, net (1,772) (7,632) (1,309) Total $ 78,272 $ 195,921 $ 309,464 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 ) 2024 2023 Deferred tax assets Property and leasehold costs $ 225,379 $ 240,065 Liabilities for dismantlements 36,719 34,258 Postretirement and other employee benefits 66,293 82,437 U. S. net operating loss 289,594 357,490 Investment in partnership 9,096 14,655 Other deferred tax assets 100,352 48,778 Total gross deferred tax assets 727,433 777,683 Less: Valuation allowance (149,498) (146,861) Net deferred tax assets 577,935 630,822 Deferred tax liabilities Deferred tax on undistributed foreign earnings (5,000) (5,000) Accumulated depreciation, depletion and amortization (811,178) (847,981) Other deferred tax liabilities (97,547) (54,052) Total gross deferred tax liabilities (913,725) (907,033) Net deferred tax (liabilities) assets $ (335,790) $ (276,211) 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 $2.6 million in 2024, 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 $1.4 billion at year-end 2024 with a corresponding deferred tax asset of $289.6 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, 2024, $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 ) 2024 2023 2022 Balance at January 1 $ 6,384 $ 3,928 $ 2,903 Additions for tax positions related to current year 1,643 — 77 Additions for tax positions related to prior year 1,952 2,456 948 Balance at December 31 $ 9,979 $ 6,384 $ 3,928 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, 2024, 2023 and 2022, 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 2025, 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 2025. 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, 2024, 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
	Dec. 31, 2024
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 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, 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, 1.2 million shares are available for grant under the 2020 Long-Term Plan at December 31, 2024. The Company also has a Stock Plan for Non-Employee Directors (NEDs) that permits the issuance of RSUs and stock options or a combination thereof to the Company’s NEDs. The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for NEDs (2021 NED Plan) and the 2018 Stock Plan for NEDs. All awards on or after May 12, 2021, were made under the 2021 NED Plan. The Company generally expects to issue treasury shares to satisfy the vesting of restricted stock and RSUs. 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 ) 2024 2023 2022 Compensation charged against income before income tax benefit $ 40,831 $ 58,760 $ 74,587 Related income tax benefit recognized in income 5,513 9,330 12,710 As of December 31, 2024, there were $46.9 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 RSU vest. Equity-Settled Awards PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023 and 2024 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. The performance conditions for the PSUs are weighted 80% on the Company’s total shareholder return (TSR) relative to an industry peer group and 20% on the return on average capital employed (ROACE), measured over the applicable performance period. ROACE is calculated by dividing the Company’s EBITDA by the average of the opening and closing Capital Employed (the sum of total equity and short-term and long-term debt). 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. The fair value of the PSUs based on the Company’s TSR 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 performance measurement 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 2024, 2023 and 2022 are presented in the following table. 2024 2023 2022 Fair value per share at grant date $41.95 $60.46 $37.77 - $47.37 Assumptions Expected volatility 50.00% 81.00% 79.00% - 81.00% Risk-free interest rate 4.14% 3.90% 1.39% - 2.85% Stock beta 1.062 1.034 1.195 - 1.200 Expected life 3.0 years 3.0 years 3.0 years The fair value of the PSUs based on ROACE was estimated based on the average high/low price of the Company’s stock on the grant date. Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2024 2023 2022 Outstanding at beginning of year 1,818,188 2,148,467 2,670,756 Granted 536,900 409,160 595,700 Vested and issued (938,599) (408,135) (654,177) Forfeited (24,068) (331,304) (463,812) Outstanding at end of year 1,392,421 1,818,188 2,148,467 TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s NEDs under the 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan. The fair value of the time-based RSUs awarded for each of the last three years is presented in the following table. Type of Plan Valuation Methodology 2024 2023 2022 Non-Employee Directors 1 Closing Stock Price at Grant Date $30.26 - $45.70 $43.27 $32.84 Long-Term Incentive Plan 2 Average High/Low Stock Price at Grant Date $37.78 - $45.98 $42.20 $29.80 - $49.86 1 Under the 2021 NED Plan, RSUs granted in 2024 are scheduled to vest in February 2025. 2 The RSUs granted under the 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 ) 2024 2023 2022 Outstanding at beginning of year 1,219,584 1,227,792 1,451,438 Granted 741,228 556,100 416,492 Vested and issued (330,444) (517,047) (462,418) Forfeited (71,768) (47,261) (177,720) Outstanding at end of year 1,558,600 1,219,584 1,227,792 STOCK OPTIONS – In 2017, the Company ceased the inclusion of stock options and SARs as a part of the long-term incentive compensation mix. As of December 31, 2023 there were no outstanding stock options. As of December 31, 2024, there were no outstanding SARs. 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 Incentive 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, 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, 2021 1,319,500 34.25 Exercisable at December 31, 2022 13,000 28.51 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 pretax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $1.7 million in 2024, $29.4 million in 2023 and $49.3 million in 2022. 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 $37.1 million, $30.9 million and $42.9 million was recorded in 2024, 2023 and 2022, respectively, for these plans.

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans	12 Months Ended
	Dec. 31, 2024
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. refining and marketing 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 ) 2024 2023 2024 2023 Change in benefit obligation Obligation at January 1 $ 699,151 $ 663,073 $ 63,808 $ 67,679 Service cost 7,042 6,542 436 495 Interest cost 33,554 34,140 2,923 3,241 Participant contributions — — 2,730 2,629 Actuarial (gain) loss 1 (35,417) 26,625 825 (5,567) Medicare Part D subsidy — — 358 299 Exchange rate changes (3,263) 6,089 (14) 2 Benefits paid (45,743) (56,296) (16,072) (4,970) Plan amendments 2 — 18,978 — — Obligation at December 31 655,324 699,151 54,994 63,808 Change in plan assets Fair value of plan assets at January 1 477,809 450,944 — — Actual return on plan assets 27,317 39,953 — — Employer contributions 35,477 37,546 12,984 2,042 Participant contributions — — 2,730 2,629 Medicare Part D subsidy — — 358 299 Exchange rate changes (2,740) 5,662 — — Benefits paid (45,743) (56,296) (16,072) (4,970) Fair value of plan assets at December 31 492,120 477,809 — — Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 1,819 3,192 — — Other accrued liabilities (10,617) (10,219) (4,237) (4,433) Deferred credits and other liabilities (154,406) (214,315) (50,757) (59,375) Fund Status and net plan liability recognized at December 31 $ (163,204) $ (221,342) $ (54,994) $ (63,808) 1 Actuarial gains in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation. 2 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. At December 31, 2024, amounts included in “Accumulated other comprehensive loss” 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) $ (163,218) $ 39,742 Prior service (credit) cost (18,233) 3,405 $ (181,451) $ 43,147 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 ) 2024 2023 2024 2023 2024 2023 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 497,947 $ 534,751 $ 489,225 $ 523,096 $ 477,983 $ 461,363 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 145,058 151,146 143,859 148,661 — — Unfunded other postretirement plans 54,994 63,808 54,994 63,808 — — 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 ) 2024 2023 2022 2024 2023 2022 Service cost $ 7,042 $ 6,542 $ 7,875 $ 436 $ 495 $ 968 Interest cost 33,554 34,140 22,747 2,923 3,241 2,211 Expected return on plan assets (33,427) (32,839) (36,458) — — — Amortization of prior service cost (credit) 2,316 620 (684) (532) (532) (532) Recognized actuarial loss (gain) 9,438 9,776 16,098 (3,586) (3,512) (615) Net periodic benefit expense 18,923 18,239 9,578 (759) (308) 2,032 Other pension costs 251 219 — — — — Total net periodic benefit expense $ 19,174 $ 18,458 $ 9,578 $ (759) $ (308) $ 2,032 The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Other ( Thousands of dollars ) 2024 2023 2024 2023 Benefit obligation at December 31 $ 115,428 $ 133,822 $ 106 $ 115 Fair value of plan assets at December 31 103,445 119,236 — — Net plan liabilities recognized (11,983) (14,586) (106) (115) Net periodic benefit expense (benefit) 1,480 1,387 (44) (44) The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2024 and 2023 and net periodic benefit expense for 2024 and 2023. Benefit Obligations Net Periodic Benefit Expense Pension Other Pension Other December 31, December 31, Year Year 2024 2023 2024 2023 2024 2023 2024 2023 Discount rate on obligation, interest cost and service cost 5.58 % 5.03 % 5.65 % 5.15 % 5.17 % 5.27 % 5.15 % 5.41 % Rate of compensation increase 3.38 % 3.52 % — — 3.50 % 3.52 % — — Cash balance interest credit rate 3.20 % 3.20 % — — — — — — Expected return on plan assets — — — — 7.19 % 7.35 % — — 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 2025 $ 49,406 $ 4,237 2026 50,193 4,252 2027 51,634 4,267 2028 51,632 4,386 2029 51,457 4,278 2030-2034 261,891 20,594 For purposes of measuring postretirement benefit obligations at December 31, 2024, the future annual rates of increase in the cost of health care were assumed to be 7.5% for 2025 decreasing each year to an ultimate rate of 4.0% in 2048 and thereafter. During 2024, the Company made contributions of $34.7 million to its domestic defined benefit pension plans and $13.0 million to its domestic postretirement benefits plan. During 2025, the Company currently expects to make contributions of $25.6 million to its domestic defined benefit pension plans, $0.8 million to its foreign defined benefit pension plans and $4.2 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 include 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, 2024 2023 Equity securities 57.3 % 62.6 % Fixed income securities 36.2 % 29.1 % Alternatives 3.7 % 5.1 % Cash equivalents 2.8 % 3.2 % 100.0 % 100.0 % The Company’s weighted average expected return on plan assets was 7.2% in 2024 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 7.2% expected return was comprised of the weighted average expected future equity securities return of 8.0% and a fixed income securities return of 5.2%. 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 3.3%. At December 31, 2024, 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 $ 87,124 $ 87,124 $ — $ — U.S. small/midcap 51,978 51,978 — — Other alternative strategies 965 — — 965 International equity 22,724 22,724 — — Emerging market equity 7,638 7,638 — — Fixed income securities: U.S. fixed income 208,755 105,302 103,453 — Cash and equivalents 9,491 9,491 — — Total Domestic Plans 388,675 284,256 103,453 965 Foreign Plans Equity securities funds 14,377 — 14,377 — Fixed income securities funds 26,500 — 26,500 — Diversified pooled fund 41,054 — 41,054 — Other 17,049 — — 17,049 Cash and equivalents 4,465 — 4,465 — Total Foreign Plans 103,445 — 86,396 17,049 Total $ 492,120 $ 284,256 $ 189,849 $ 18,014 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 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 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. The latter of these investments was sold during 2024. 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, 2022 $ 32,734 Actual return on plan assets: Relating to assets held at the reporting date 711 Purchases, sales and settlements (8,991) Total at December 31, 2023 24,454 Actual return on plan assets: Relating to assets held at the reporting date (3,574) Relating to assets sold during the period (2,865) Total at December 31, 2024 $ 18,015 401(K) PLANS - Most full-time U.S. employees of the Company may participate in a 401(k) 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 $8.7 million in 2024, $8.5 million in 2023 and $6.0 million in 2022.

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2024
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 NYMEX. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Commodity Price Risks The Company is subject to commodity price risk related to products it produces and sells. During 2024, the Company entered into natural gas swap contracts that will be effective in 2025. Under the swap contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. At December 31, 2024 volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 20 $ 3.20 1/1/2025 1/31/2025 Subsequent to year end, the Company entered into additional natural gas derivative contracts. Volumes per day and the weighted average prices for these contracts are as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 40 $ 3.58 2/1/2025 6/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.65 7/1/2025 9/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.74 10/1/2025 12/31/2025 At December 31, 2023 the Company did not have any outstanding crude oil or natural gas derivative contracts. 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, 2024 and 2023. At December 31, 2024 and 2023, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. See also Note O . ( Thousands of dollars ) Asset (Liability) Derivatives Fair Value at December 31, Type of Derivative Contract Balance Sheet Location 2024 2023 Commodity swaps Accounts payable $ (1,707) — 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 2024 2023 2022 Commodity swaps Loss on derivative instruments $ (1,707) $ — $ (160,690) Commodity collars Loss on derivative instruments — — (159,721) Credit Risks The Company is subject to credit risks primarily 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.

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	Note L – Net Income (Loss) Per Common 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 ) 2024 2023 2022 Basic method 150,011,458 155,233,560 155,276,533 Dilutive stock options and restricted stock units 1,015,894 1,412,869 2,198,305 Diluted method 151,027,352 156,646,429 157,474,838 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 diluted earnings per share because the incremental shares from the assumed conversion were antidilutive. 2024 2023 2022 Antidilutive stock options excluded from diluted shares — — 126,000 Weighted average price of these options — — $49.65

Other Financial Information

Other Financial Information	12 Months Ended
	Dec. 31, 2024
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 $45.4 million gain in 2024, $10.8 million loss in 2023 and $23.0 million gain in 2022. Supplemental Information to Statement of Cash Flows ( Thousands of dollars ) 2024 2023 2022 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ 71,081 $ 47,151 $ (137,228) (Increase) decrease in inventories 1,327 329 (1,534) (Increase) decrease in prepaid expenses 1,192 (1,293) (3,413) Increase (decrease) in accounts payable and accrued liabilities ¹ 3,287 (140,011) 69,854 Increase (decrease) in income taxes payable (2,004) (5,537) 6,593 Net decrease (increase) in non-cash operating working capital $ 74,883 $ (99,361) $ (65,728) Supplementary disclosures: Cash income taxes paid, net of refunds $ 12,648 $ 12,356 $ 24,853 Interest paid, net of amounts capitalized of $11.4 million in 2024, $14.5 million in 2023 and $16.3 million in 2022 78,806 108,912 149,597 Non-cash investing activities: Asset retirement costs capitalized $ 47,233 $ 32,975 $ (21,147) (Increase) decrease in capital expenditure accrual (5,935) 17,517 (31,397) 1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2024
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Loss	Note N – Accumulated Other Comprehensive Loss The components of ”Accumulated other comprehensive loss” 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, 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 36,598 (23,029) 13,569 Balance at December 31, 2023 (381,632) (139,485) (521,117) 2024 components of other comprehensive income (loss): Before reclassifications to income (134,692) 23,713 (110,979) Reclassifications to income — 4,024 ¹ 4,024 Net other comprehensive income (loss) (134,692) 27,737 (106,955) Balance at December 31, 2024 $ (516,324) $ (111,748) $ (628,072) 1 Reclassifications before taxes of $5.4 million and $5.6 million are included in the computation of net periodic benefit expense in 2024 and 2023, respectively. See Note J for additional information. Related income taxes of $1.4 million and $1.1 million are included in income tax expense in 2024 and 2023, respectively.

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 19,469 $ — $ — $ 19,469 $ 17,785 $ — $ — $ 17,785 Commodity swaps — 1,707 — 1,707 — — — — $ 19,469 $ 1,707 $ — $ 21,176 $ 17,785 $ — $ — $ 17,785 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. The commodity swaps liability as of December 31, 2024 was $1.7 million and recorded as “Accounts payable” in the Consolidated Balance Sheets. The fair value of the commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in fair value of natural gas derivative contracts is recorded in “(Loss) Gain on derivative instruments” in the Consolidated Statements of Operations. The Company acquired Gulf of America assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (collectively, LLOG) and, in a separate agreement, from Petrobras America Inc. (PAI) in 2019 and 2018, respectively. Under the terms of both transactions, contingent consideration was paid after meeting specified revenue thresholds and project milestones and recorded to “Contingent consideration payment” in the Consolidated Statements of Cash Flows. 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, was no longer subject to fair value measurement. The liability was 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 income (loss)” 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, 2024 and 2023. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2024 and 2023. 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, 2024 2023 ( Thousands of dollars ) Carrying Fair Carrying Fair Financial liabilities: Current and long-term debt $ 1,275,374 $ 1,185,961 $ 1,329,075 $ 1,265,185 Fair Values – Nonrecurring Impairment expenses of $62.9 million were incurred in 2024. In the first quarter of 2024, an impairment charge of $34.5 million was triggered for the Calliope field, and in the fourth quarter of 2024, an impairment charge of $28.4 million was triggered for the Nearly Headless Nick field. Both of the impairments were due to operational issues that led to reserve reductions. There were no impairment expenses incurred in 2023. The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region. The fair value information associated with the impaired properties is presented in the following table: Year Ended December 31, 2024 Net Book Total Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 2024 Assets: Impaired proved properties United States - Offshore $ — — 501 63,410 62,909

Commitments

Commitments	12 Months Ended
	Dec. 31, 2024
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 U.S. Offshore transportation contracts require minimum monthly payments through 2045, while the Canada Onshore transportation 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 $148.8 million in 2025, $117.7 million in 2026, $105.5 million in 2027, $96.0 million in 2028 and $64.2 million in 2029. 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 $225.9 million in 2024, $295.1 million in 2023 and $216.4 million in 2022. Commitments for capital expenditures were approximately $417.0 million at December 31, 2024, including $53.6 million for the Gulf of America, $112.2 million for Eagle Ford Shale, $31.2 million for Canada and $220.0 million for Other Offshore, mainly for capital projects in Vietnam. Commitments for operating agreements include approximately $178.0 million at December 31, 2024 for Other Offshore for the purpose of supporting future development activities in Vietnam.

Environmental and Other Conting

Environmental and Other Contingencies	12 Months Ended
	Dec. 31, 2024
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 natural 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 natural 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 March 2024, the U.S. EPA published 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 U.S. EPA. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. The charge, referred to as the WEC, is a component of the Biden Administration’s Methane Emissions Reduction Program to limit methane emissions from the oil and gas industry under the 2022 IRA. 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. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement again. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. 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
	Dec. 31, 2024
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 ) 2024 2023 2022 Beginning of year 152,748,642 155,467,319 154,463,050 Stock options exercised 1 — 2,657 181,655 Restricted stock awards 1 1,105,268 689,824 822,614 Treasury shares purchased (8,008,786) (3,411,158) — End of year 145,845,124 152,748,642 155,467,319 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. The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock. 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. During the year ended December 31, 2024, the Company repurchased 8.0 million shares of its common stock under the share repurchase program for $300.0 million ($302.7 million including excise taxes and fees). As of December 31, 2024, the Company had $650.1 million of its common stock remaining available to repurchase under the program. Subsequent to year end, as of February 25, 2025, the Company repurchased 3.4 million shares of its common stock in open-market transactions for $95.1 million, excluding taxes and fees. As of this date, the Company had $555.0 million of its common stock remaining available to repurchase under the program. 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 and Form 8-K filed on August 8, 2024.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2024
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 U.S., Canada and all other countries. Each of these segments derive revenues primarily from the sale of crude oil, NGLs and/or natural gas. The Company’s management team and Chief Operating Decision Maker (CODM) evaluates segment performance-based on income (loss) from operations, excluding interest income and interest expense, and allocates financial and capital resources for each segment predominantly in the annual budget and forecasting process. The CODM also considers budget-to-actual variances on a monthly basis for the performance measure when making decisions about allocating capital and personnel to the segments. For the income statement periods presented in these financial statements, Murphy’s former CEO, Roger Jenkins, acted as the CODM. As of January 1, 2025, Murphy appointed a new CEO, Eric Hambly. 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. 2024 2023 2022 Chevron Corporation 13 % 16 % 19 % ExxonMobil Corporation 20 % 27 % 12 % Phillips 66 10 % N/A N/A Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices. No assets were held for sale as of December 31, 2024 and 2023. The former U.K., Malaysia and U.S. refining and marketing 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 and natural gas contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. “Other segment costs” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM, or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs” for the years presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Other, and Discontinued Operations Consolidated Year ended December 31, 2024 Revenue from production $ 2,503.8 $ 504.5 $ 6.6 $ 3,014.9 $ — $ 3,014.9 Sales of purchased natural gas — 3.7 — 3.7 — 3.7 Gain on sales of assets and other operating income 4.5 1.5 — 6.0 3.9 9.9 Revenues from external customers 2,508.3 509.7 6.6 3,024.6 3.9 3,028.5 Lease operating expenses Lease operating expenses and taxes other than income 471.3 176.8 1.6 649.7 — 649.7 Repair and maintenance 63.7 4.8 — 68.5 — 68.5 Workovers 214.9 3.9 — 218.8 — 218.8 Total lease operating expenses 749.9 185.5 1.6 937.0 — 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 — 3.1 Selling and general expenses (3.3) 20.4 6.7 23.8 89.1 112.9 Exploration Expenses — Geological and geophysical 14.4 0.2 12.6 27.2 — 27.2 Dry holes and previously suspended exploration costs 70.9 — 2.3 73.2 — 73.2 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 10.9 0.3 21.9 33.1 — 33.1 Total exploration expenses 96.2 0.5 36.8 133.5 — 133.5 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 8.9 865.8 Impairment of assets 62.9 — — 62.9 — 62.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 0.1 52.5 Other operating expenses 9.3 2.8 2.1 14.2 (3.2) 11.0 Interest Income (22.0) — — (22.0) (12.2) (34.2) Interest (expense), net of capitalization 0.2 0.4 0.2 0.8 105.1 105.9 Income tax expense Current income tax expense 1.5 3.2 0.2 4.9 0.9 5.8 Deferred income tax expense 123.8 8.8 (31.2) 101.4 (28.9) 72.5 Total income tax expense 125.3 12.0 (31.0) 106.3 (28.0) 78.3 Other segment costs (income) 6.9 0.1 0.3 7.3 (44.0) (36.7) Segment income (loss) - including NCI 1 $ 561.9 $ 49.0 $ (12.5) $ 598.4 $ (111.9) $ 486.5 Additions to property, plant, equipment $ 601.7 $ 137.9 $ 71.8 $ 811.4 $ 29.2 $ 840.6 Total assets at year-end 6,953.8 1,919.8 302.0 9,175.6 491.9 9,667.5 1 Includes results attributable to a noncontrolling interest in MP GOM. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Consolidated Year ended December 31, 2023 Revenue from production $ 2,921.8 $ 443.8 $ 11.0 $ 3,376.6 $ — $ 3,376.6 Sales of purchased natural gas — 72.2 — 72.2 — 72.2 Gain on sales of assets and other operating income 6.5 1.5 — 8.0 3.3 11.3 Revenues from external customers 2,928.3 517.5 11.0 3,456.8 3.3 3,460.1 Lease operating expenses Lease operating expenses and taxes other than income 532.3 144.7 1.9 678.9 — 678.9 Repair and maintenance 53.2 5.0 — 58.2 — 58.2 Workovers 45.2 2.1 — 47.3 — 47.3 Total lease operating expenses 630.7 151.8 1.9 784.4 — 784.4 Severance and ad valorem taxes 41.4 1.4 — 42.8 — 42.8 Transportation, gathering and processing 157.0 76.0 — 233.0 — 233.0 Costs of purchased natural gas — 51.7 — 51.7 — 51.7 Selling and general expenses 11.8 16.5 9.4 37.7 81.2 118.9 Exploration Expenses — Geological and geophysical 6.6 0.1 19.4 26.1 — 26.1 Dry holes and previously suspended exploration costs 153.1 — 16.7 169.8 — 169.8 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 14.9 0.4 23.6 38.9 — 38.9 Total exploration expenses 174.6 0.5 59.7 234.8 — 234.8 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 Other operating expenses Other miscellaneous operating expenses 20.1 15.5 8.1 43.7 (4.4) 39.3 Loss on contingent consideration 7.1 — — 7.1 — 7.1 Total other operating expenses 27.2 15.5 8.1 50.8 (4.4) 46.4 Interest Income (3.3) — — (3.3) (9.3) (12.6) Interest expense, net of capitalization 0.1 0.2 0.2 0.5 111.9 112.4 Income tax expense Current income tax expense 3.1 3.7 0.6 7.4 8.8 16.2 Deferred income tax expense 229.6 7.5 (6.7) 230.4 (50.6) 179.8 Total income tax expense 232.7 11.2 (6.1) 237.8 (41.8) 196.0 Other segment costs (income) 7.2 1.1 0.6 8.9 12.1 21.0 Segment income (loss) - including NCI 1 $ 905.1 $ 41.6 $ (65.5) $ 881.2 $ (157.5) $ 723.7 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 9,400.2 366.5 9,766.7 1 Includes results attributable to a noncontrolling interest in MP GOM. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Consolidated Year ended December 31, 2022 Revenue from production $ 3,435.5 $ 580.0 $ 23.0 $ 4,038.5 $ — $ 4,038.5 Sales of purchased natural gas 0.2 181.5 — 181.7 — 181.7 Gain on sales of assets and other operating income (loss) 25.5 1.4 — 26.9 (314.4) (287.5) Revenues from external customers 3,461.2 762.9 23.0 4,247.1 (314.4) 3,932.7 Lease operating expenses Lease operating expenses and taxes other than income 458.2 147.9 1.5 607.6 — 607.6 Repair and maintenance 34.9 4.7 — 39.6 — 39.6 Workovers 29.6 2.5 — 32.1 — 32.1 Total lease operating expenses 522.7 155.1 1.5 679.3 — 679.3 Severance and ad valorem taxes 55.7 1.3 — 57.0 — 57.0 Transportation, gathering and processing 142.2 70.5 — 212.7 — 212.7 Costs of purchased natural gas 0.2 171.8 — 172.0 — 172.0 Selling and general expenses 20.4 21.9 2.2 44.5 88.8 133.3 Exploration Expenses — Geological and geophysical 8.3 0.4 1.8 10.5 — 10.5 Dry holes and previously suspended exploration costs 23.0 — 59.1 82.1 — 82.1 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 16.2 0.7 23.7 40.6 — 40.6 Total exploration expenses 47.5 1.1 84.6 133.2 — 133.2 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 Other operating expenses Other miscellaneous operating expenses 41.3 10.5 2.4 54.2 5.0 59.2 Loss on contingent consideration 78.3 — — 78.3 — 78.3 Total other operating expenses 119.6 10.5 2.4 132.5 5.0 137.5 Interest Income (0.3) — — (0.3) (2.5) (2.8) Interest expense, net of capitalization 0.1 — 0.3 0.4 150.4 150.8 Income tax expense Current income tax expense 8.1 8.8 2.3 19.2 4.2 23.4 Deferred income tax expense 362.7 34.8 0.6 398.1 (112.0) 286.1 Total income tax expense 370.8 43.6 2.9 417.3 (107.8) 309.5 Other segment costs (income) 6.9 1.8 0.6 9.3 (20.8) (11.5) Segment income (loss) - including NCI 1 $ 1,521.9 $ 134.2 $ (77.0) $ 1,579.1 $ (440.4) $ 1,138.7 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 1,035.4 10,309.0 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 2024 $ 6,415.9 $ 1,389.5 $ 249.2 $ 8,054.6 2023 6,555.0 1,497.3 172.8 8,225.1 2022 6,562.8 1,499.1 166.1 8,228.0 1 Certain long-lived assets at December 31 represent total non-current assets, excluding investments, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

Leases

Leases	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Leases	Note T – Leases Nature of Leases The Company has entered into various operating and financial 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 16 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 the 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 2024 2023 Operating lease 1, 2 Lease operating expenses $ 411,303 $ 246,721 Operating lease 2 Transportation, gathering and processing 16,117 37,797 Operating lease 2 Selling and general expenses 10,990 9,859 Operating lease 2 Other operating expense 6,622 675 Operating lease 2 Exploration expenses 38,974 110,577 Operating lease 2 Property, plant and equipment 277,170 204,595 Operating lease 2 Asset retirement obligations 10 57,442 Finance lease Amortization of asset Depreciation, depletion and amortization 855 1,505 Interest on lease liabilities Interest expense, net 193 221 Sublease income Other income (1,143) (1,402) Net lease expense $ 761,091 $ 667,990 1 Variable lease expenses. For the years ended December 31, 2024 and 2023, includes variable lease expenses of $42.3 million and $36.7 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, 2024, includes $236.4 million in lease operating expenses, $13.0 million for “Transportation, gathering and processing”, $38.5 million for “Exploration expenses, including undeveloped lease amortization”, $0.8 million in “Selling and general expenses”, $6.2 million in “Other operating expense”, $97.1 million in “Property, plant and equipment, net” and nil 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, 2023, includes $78.2 million in lease operating expenses, $29.4 million in “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. Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2025 $ 290,474 $ 1,257 $ 291,731 2026 123,487 1,257 124,744 2027 66,521 1,257 67,778 2028 59,398 1,257 60,655 2029 56,849 456 57,305 Remaining 406,450 927 407,377 Total future minimum lease payments 1,003,179 6,411 1,009,590 Less imputed interest (212,590) (1,534) (214,124) Present value of lease liabilities 1 $ 790,589 $ 4,877 $ 795,466 1 Includes both the current and long-term portion of the lease liabilities. Lease Term and Discount Rate December 31, 2024 December 31, 2023 Weighted average remaining lease term: Operating leases 8 years 10 years Finance leases 6 years 5 years Weighted average discount rate: Operating leases 5.7 % 5.9 % Finance leases 4.9 % 4.7 % Other Information Year Ended December 31, (Thousands of dollars) 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 328,847 $ 271,488 Operating cash flows from finance leases 311 221 Financing cash flows from finance leases 665 622 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 349,312 $ 5,923 1 For the year ended December 31, 2024, right-of-use assets obtained in exchange for lease liabilities primarily includes $254.1 million related to the extension of an operating lease pertaining to a drill ship used in our U.S. Offshore business and $52.7 million pertaining to two drilling rigs and several natural gas compressor units at our U.S. Onshore business. December 31, 2023 includes $4.5 million related to natural gas compressor units at various U.S. Onshore locations.
Leases	Note T – Leases Nature of Leases The Company has entered into various operating and financial 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 16 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 the 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 2024 2023 Operating lease 1, 2 Lease operating expenses $ 411,303 $ 246,721 Operating lease 2 Transportation, gathering and processing 16,117 37,797 Operating lease 2 Selling and general expenses 10,990 9,859 Operating lease 2 Other operating expense 6,622 675 Operating lease 2 Exploration expenses 38,974 110,577 Operating lease 2 Property, plant and equipment 277,170 204,595 Operating lease 2 Asset retirement obligations 10 57,442 Finance lease Amortization of asset Depreciation, depletion and amortization 855 1,505 Interest on lease liabilities Interest expense, net 193 221 Sublease income Other income (1,143) (1,402) Net lease expense $ 761,091 $ 667,990 1 Variable lease expenses. For the years ended December 31, 2024 and 2023, includes variable lease expenses of $42.3 million and $36.7 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, 2024, includes $236.4 million in lease operating expenses, $13.0 million for “Transportation, gathering and processing”, $38.5 million for “Exploration expenses, including undeveloped lease amortization”, $0.8 million in “Selling and general expenses”, $6.2 million in “Other operating expense”, $97.1 million in “Property, plant and equipment, net” and nil 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, 2023, includes $78.2 million in lease operating expenses, $29.4 million in “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. Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2025 $ 290,474 $ 1,257 $ 291,731 2026 123,487 1,257 124,744 2027 66,521 1,257 67,778 2028 59,398 1,257 60,655 2029 56,849 456 57,305 Remaining 406,450 927 407,377 Total future minimum lease payments 1,003,179 6,411 1,009,590 Less imputed interest (212,590) (1,534) (214,124) Present value of lease liabilities 1 $ 790,589 $ 4,877 $ 795,466 1 Includes both the current and long-term portion of the lease liabilities. Lease Term and Discount Rate December 31, 2024 December 31, 2023 Weighted average remaining lease term: Operating leases 8 years 10 years Finance leases 6 years 5 years Weighted average discount rate: Operating leases 5.7 % 5.9 % Finance leases 4.9 % 4.7 % Other Information Year Ended December 31, (Thousands of dollars) 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 328,847 $ 271,488 Operating cash flows from finance leases 311 221 Financing cash flows from finance leases 665 622 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 349,312 $ 5,923 1 For the year ended December 31, 2024, right-of-use assets obtained in exchange for lease liabilities primarily includes $254.1 million related to the extension of an operating lease pertaining to a drill ship used in our U.S. Offshore business and $52.7 million pertaining to two drilling rigs and several natural gas compressor units at our U.S. Onshore business. December 31, 2023 includes $4.5 million related to natural gas compressor units at various U.S. Onshore locations.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
Subsequent Event	Note U – Subsequent Event On January 30, 2025, the Board of Directors of Murphy Oil Corporation (NYSE: MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $0.325 per share, or $1.30 per share on an annualized basis. The dividend is payable on March 3, 2025, to stockholders of record as of February 18, 2025.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2024
Oil and Gas Disclosure [Abstract]
Supplemental Oil and Gas Information	The following unaudited schedules are presented in accordance with required disclosures about Oil and 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, natural gas and NGLs 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 judgments 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 2024 were $75.48 per BBL for NYMEX crude oil (WTI) and $2.13 per MCF for natural gas (Henry Hub). The average prices used for 2023 were $78.22 per BBL 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 BBL for NYMEX crude oil (WTI) and $6.36 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 NGLs. All crude oil, natural gas and NGL 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 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, 2024. Equivalents ( Millions of barrels of oil equivalent ) Total United Canada Other Proved developed and undeveloped reserves: 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 — — Sale 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 Sale of properties (5.2) — (5.2) — Production (70.4) (45.3) (25.0) (0.1) December 31, 2023 739.5 311.1 415.5 12.9 Revisions of previous estimates 14.3 8.1 6.3 (0.1) Improved recovery 11.3 11.3 — — Extensions and discoveries 31.4 16.0 15.4 — Production (67.5) (39.1) (28.3) (0.1) December 31, 2024 ¹ 729.0 307.4 408.9 12.7 Proved developed reserves: 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 425.5 223.2 202.0 0.3 December 31, 2024 ² 436.2 218.9 217.1 0.2 Proved undeveloped reserves: 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 314.0 87.9 213.5 12.6 December 31, 2024 ³ 292.8 88.5 191.8 12.5 1 Total and United States includes proved reserves of 15.9 MMBOE, consisting of 14.5 MMBBL of oil, 0.6 MMBBL of NGLs and 5 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 14.4 MMBOE, consisting of 13.2 MMBBL of oil, 0.5 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.5 MMBOE, consisting of 1.3 MMBBL of oil, 0.1 MMBBL of NGLs and 0.8 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. 2024 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney. Improved Recovery – Proved equivalent reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved equivalent reserves were added for drilling activities predominantly in Tupper Montney, the Eagle Ford Shale, and projects in the Gulf of America. 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 Tupper Montney, the Eagle Ford Shale, and Vietnam. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest, in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 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 Gulf of America. Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Tupper Montney and Kaybob Duvernay, as well as the Gulf of America and Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. ( Millions of barrels ) Total United Canada Other Proved developed and undeveloped crude oil reserves: 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 — — Sale 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 Sale of properties (2.0) — (2.0) — Production (37.9) (35.6) (2.2) (0.1) December 31, 2023 275.8 228.0 35.4 12.4 Revisions of previous estimates 6.6 6.6 0.1 (0.1) Improved recovery 10.7 10.7 — — Extensions and discoveries 16.6 10.7 5.9 — Production (34.6) (30.8) (3.7) (0.1) December 31, 2024 ¹ 275.1 225.2 37.7 12.2 Proved developed crude oil reserves: 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 186.3 163.7 22.3 0.3 December 31, 2024 ² 184.7 164.1 20.4 0.2 Proved undeveloped crude oil reserves: 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 89.5 64.3 13.1 12.1 December 31, 2024 ³ 90.4 61.1 17.3 12.0 1 Total and United States includes proved reserves of 14.5 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 13.2 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.3 MMBBL attributable to the noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. 2024 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The crude oil reserves revisions in 2024 resulted predominantly from performance adjustments in the Eagle Ford Shale and Gulf of America. Improved Recovery – Proved oil reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and Gulf of America. 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 Gulf of America. Extensions and discoveries - In 2023, proved oil reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale and Vietnam. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 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 Gulf of America 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 Gulf of America and the Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. ( Millions of barrels ) Total United Canada Other Proved developed and undeveloped NGL reserves: 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 — Purchase of properties 0.3 0.3 — — Sale 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 — Sale of properties (0.6) — (0.6) — Production (4.1) (3.8) (0.3) — December 31, 2023 37.6 34.3 3.3 — Revisions of previous estimates 1.2 0.3 0.9 — Improved recovery 0.4 0.4 — — Extensions and discoveries 2.9 2.4 0.5 — Production (3.5) (3.3) (0.2) — December 31, 2024 ¹ 38.6 34.1 4.5 — Proved developed NGL reserves: December 31, 2021 28.4 25.6 2.8 — December 31, 2022 29.7 27.4 2.3 — December 31, 2023 25.9 24.1 1.8 — December 31, 2024 ² 24.1 21.9 2.2 — Proved undeveloped NGL reserves: December 31, 2021 10.0 9.5 0.5 — December 31, 2022 12.0 10.2 1.8 — December 31, 2023 11.7 10.2 1.5 — December 31, 2024 ³ 14.5 12.2 2.3 — 1 Total and United States includes total proved reserves of 0.6 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 0.5 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.1 MMBBL attributable to the noncontrolling interest in MP GOM. 2024 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The NGL reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney. Improved Recovery – Proved NGL reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved NGL reserves were added for drilling activities predominantly in Tupper Montney and Eagle Ford Shale. 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 Gulf of America. Extensions and discoveries - In 2023, proved NGL reserves were added for drilling and expansion activities predominantly in 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 non-operated Placid Montney assets. 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 Gulf of America, Eagle Ford Shale, and Kaybob Duvernay. Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the Gulf of America and Eagle Ford Shale, as well as in Tupper Montney and Kaybob Duvernay. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. ( Billions of cubic feet ) Total United Canada Other Proved developed and undeveloped natural gas reserves: 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 Sale of properties (15.6) — (15.6) — Production (170.1) (35.1) (135.0) — December 31, 2023 2,556.2 293.1 2,260.1 3.0 Revisions of previous estimates 39.1 7.7 31.4 — Improved recovery 1.2 1.2 — — Extensions and discoveries 71.4 17.0 54.4 — Production (176.1) (30.1) (146.0) — December 31, 2024 1,4 2,491.8 288.9 2,199.9 3.0 Proved developed natural gas reserves: 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 1,279.3 212.4 1,066.7 0.2 December 31, 2024 2,4 1,364.2 196.8 1,167.2 0.2 Proved undeveloped natural gas reserves: December 31, 2021 1,126.4 72.2 1,054.1 — December 31, 2022 1,036.8 80.8 956.0 — December 31, 2023 1,276.9 80.7 1,193.4 2.8 December 31, 2024 ³ 1,127.6 92.1 1,032.7 2.8 1 Total and United States includes total proved reserves of 5.0 BCF attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.8 BCF attributable to the noncontrolling interest in MP GOM. 4 Includes proved natural gas reserves to be consumed in operations as fuel of 67.9 BCF, 36.0 BCF and 2.8 BCF for the U.S., Canada and Other, respectively, with 1.1 BCF attributable to the noncontrolling interest in MP GOM. 5 Totals within the tables may not add as a result of rounding. 2024 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The natural gas reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney. Improved Recovery – Proved natural gas reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved natural gas reserves were added for drilling activities predominantly in Tupper Montney and Eagle Ford Shale. 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 Eagle Ford Shale. These negative revisions were partially offset by positive revisions in the Gulf of America, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney. Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in 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 non-operated Placid Montney assets. 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 Tupper Montney. Extensions and discoveries - In 2022, proved natural gas reserves were added for drilling and expansion activities predominantly in Tupper Montney, as well as in the Gulf of America and Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America and divested certain working interests in the Gulf of America and Eagle Ford Shale. ( Millions of dollars ) United Canada Other Total Year ended December 31, 2024 Property acquisition costs Unproved $ 7.8 $ 0.2 $ — $ 8.0 Proved — — — — Total acquisition costs 7.8 0.2 — 8.0 Exploration costs 85.3 0.4 60.2 145.9 Development costs 598.7 137.7 45.1 781.5 Total costs incurred 691.8 138.3 105.3 935.4 Charged to expense Dry hole expense 70.9 — 2.3 73.2 Geophysical and other costs 19.2 0.4 31.2 50.8 Total charged to expense 90.1 0.4 33.5 124.0 Property additions $ 601.7 $ 137.9 $ 71.8 $ 811.4 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 ( Millions of dollars ) United Canada Other Total Year ended December 31, 2024 Revenues Crude oil and natural gas liquids sales $ 2,436.0 $ 272.3 $ 6.6 $ 2,714.9 Natural gas sales 67.8 232.2 — 300.0 Sales of purchased natural gas — 3.7 — 3.7 Total oil and natural gas revenues 2,503.8 508.2 6.6 3,018.6 Other operating revenues 4.5 1.5 6.0 Total revenues 2,508.3 509.7 6.6 3,024.5 Costs and expenses Lease operating expenses 749.9 185.5 1.6 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 Exploration costs charged to expense 90.0 0.4 33.5 123.9 Undeveloped lease amortization 6.2 0.1 3.3 9.6 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 Impairment of assets 62.9 — — 62.9 Selling and general expenses (3.3) 20.4 6.7 23.8 Other expenses (benefits) (5.6) 3.3 2.6 0.3 Total costs and expenses 1,821.1 448.7 50.1 2,319.9 Results of operations before taxes 687.2 61.0 (43.5) 704.6 Income tax expense (benefit) 125.3 12.0 (31.0) 106.3 Results of operations $ 561.9 $ 49.0 $ (12.5) $ 598.4 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 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 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, 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 December 31, 2024 Future cash inflows $ 18,118.1 $ 6,304.4 $ 1,012.9 $ 25,435.4 Future development costs (2,024.9) (825.9) (252.5) (3,103.3) Future production costs (7,645.7) (4,026.5) (341.7) (12,013.9) Future income taxes (893.5) (251.2) (203.4) (1,348.1) Future net cash flows 7,554.0 1,200.8 215.3 8,970.1 10% annual discount for estimated timing of cash flows (2,887.3) (486.0) (200.9) (3,574.2) Standardized measure of discounted future net cash flows $ 4,666.7 $ 714.8 $ 14.4 $ 5,395.9 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 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 ( Millions of dollars ) 2024 2023 2022 Net changes in prices and production costs 2 $ (1,116.5) $ (5,845.6) $ 4,812.2 Net changes in development costs (152.7) (78.8) (531.1) Sales and transfers of oil and natural gas produced, net of production costs (1,824.8) (2,264.8) (2,917.4) Net change due to extensions and discoveries 583.7 770.4 1,223.5 Net change due to purchases and sales of proved reserves — (96.1) 102.1 Development costs incurred 668.6 703.7 769.3 Accretion of discount 773.5 1,393.3 802.6 Revisions of previous quantity estimates (688.1) (771.5) 1,652.9 Net change in income taxes 298.8 1,229.6 (1,399.9) Net (decrease) increase (1,457.5) (4,959.8) 4,514.2 Standardized measure at January 1 6,853.4 11,813.2 7,299.0 Standardized measure at December 31 $ 5,395.9 $ 6,853.4 $ 11,813.2 1 Includes noncontrolling interest in MP GOM. 2 The average prices used for 2024 were $75.48 per BBL for NYMEX crude oil (WTI) and $2.13 per MCF for natural gas (Henry Hub). The average prices used for 2023 were $78.22 per BBL 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 BBL for NYMEX crude oil (WTI) and $6.36 per MCF for natural gas (Henry Hub). ( Millions of dollars ) United Canada Other Total December 31, 2024 Unproved oil and natural gas properties 1 $ 247.3 $ 6.6 $ 29.1 $ 283.0 Proved oil and natural gas properties 16,598.8 4,498.1 246.7 21,343.6 Gross capitalized costs 16,846.1 4,504.7 275.8 21,626.6 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties (111.0) — (20.7) (131.7) Proved oil and natural gas properties (10,326.2) (3,116.2) (44.2) (13,486.6) Net capitalized costs $ 6,408.9 $ 1,388.5 $ 210.9 $ 8,008.3 December 31, 2023 Unproved oil and natural gas properties 1 $ 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 1 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
	Dec. 31, 2024
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, 2024 Revenue from contracts with customers $ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6 Income from continuing operations before income taxes 145.6 189.6 153.8 78.6 567.6 Income from continuing operations 115.5 156.9 151.7 65.2 489.3 Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5 Net income attributable to Murphy 90.0 127.7 139.1 50.3 407.1 Income from continuing operations per common share ² Basic 0.60 0.84 0.93 0.35 2.73 Diluted 0.60 0.83 0.93 0.34 2.72 Net income per common share ² Basic 0.59 0.84 0.93 0.35 2.71 Diluted 0.59 0.83 0.93 0.34 2.70 Cash dividend per common share 0.300 0.300 0.300 0.300 1.200 Year ended December 31, 2023 Revenue from contracts with customers $ 840.0 $ 812.9 $ 953.8 $ 842.2 $ 3,448.9 Income from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0 Income from continuing operations 214.0 92.5 278.2 140.5 725.2 Net income including noncontrolling interest 214.3 91.9 277.8 139.7 723.7 Net income attributable to Murphy 191.6 98.3 255.3 116.4 661.6 Income 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 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 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
	Dec. 31, 2024
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 2024 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6 Deferred tax asset valuation allowance 146.9 2.6 — — 149.5 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

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net income (loss)	$ 50,300	$ 139,100	$ 127,700	$ 90,000	$ 116,400	$ 255,300	$ 98,300	$ 191,600	$ 407,171	$ 661,559	$ 965,047

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
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

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Murphy’s cybersecurity environment and risk strategy is broadly managed by the Company’s Information Technology (IT) group, which oversees the Company’s IT and Operational Technology (OT) infrastructure. Within the IT group, the Murphy Cybersecurity Team (MCT) is specifically responsible for monitoring and managing security of the enterprise IT and OT network and systems, including developing and deploying administrative policies, technical controls, and safety protocols necessary to prevent unauthorized access, theft, damage, or loss of Company data or systems. All members of the MCT hold globally-recognized security certifications and have wide-ranging experience in cybersecurity matters. The Incident Management Team (IMT) is responsible for responding to active security threats and incidents as they occur. The Chief Information Officer oversees the IT group and is a member of the IMT, and provides briefings to the CEO, the executive leadership team, and the Audit Committee of the Board regarding cybersecurity risks, strategy, and management at least annually. The Audit Committee is ultimately responsible for overseeing cybersecurity strategy and ensuring that management has sufficient resources, programs, and processes in place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the Board as appropriate. We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected. Murphy considers its cybersecurity risk management framework to be a core component of its overall enterprise risk management system. The cybersecurity risk management framework directly aligns with the National Institute of Standards and Technology Cybersecurity Framework and involves regular review and update of security policies and procedures; leverage of industry-leading technologies focused on continuously monitoring, analyzing, and defending against intrusions; regular testing of such technologies and other controls; periodic simulations of security incidents; and constant monitoring of the broader cybersecurity environment for new and emerging threats. The Company also requires employees to attend regular cybersecurity training and education to mitigate cybersecurity risks. To remain informed of the cybersecurity landscape, the Company collaborates with peers, third-party advisors, industry groups and policymakers. Murphy engages cybersecurity assessors, consultants, our internal auditors, and other third parties both periodically and as appropriate when cyber threats are identified. Murphy utilizes these consultants to perform forensic analysis of data published by threat actors, to monitor and scan Murphy’s systems for threat vectors, and to consult on emerging cybersecurity environment topics. In addition to monitoring its own IT systems, Murphy also has processes in place to identify cybersecurity risks and threats associated with third party service providers and partners. These processes include conducting vendor due diligence and risk assessments, participating in industry information sharing groups, subscribing to cybersecurity notification services, and maintaining ongoing collaboration with federal agencies.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	In addition to monitoring its own IT systems, Murphy also has processes in place to identify cybersecurity risks and threats associated with third party service providers and partners. These processes include conducting vendor due diligence and risk assessments, participating in industry information sharing groups, subscribing to cybersecurity notification services, and maintaining ongoing collaboration with federal agencies.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The Audit Committee is ultimately responsible for overseeing cybersecurity strategy and ensuring that management has sufficient resources, programs, and processes in place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the Board as appropriate. We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Audit Committee is ultimately responsible for overseeing cybersecurity strategy and ensuring that management has sufficient resources, programs, and processes in place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Audit Committee also reports material cybersecurity risks to the Board as appropriate.
Cybersecurity Risk Role of Management [Text Block]	The Incident Management Team (IMT) is responsible for responding to active security threats and incidents as they occur. The Chief Information Officer oversees the IT group and is a member of the IMT, and provides briefings to the CEO, the executive leadership team, and the Audit Committee of the Board regarding cybersecurity risks, strategy, and management at least annually. The Audit Committee is ultimately responsible for overseeing cybersecurity strategy and ensuring that management has sufficient resources, programs, and processes in place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the Board as appropriate. We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Within the IT group, the Murphy Cybersecurity Team (MCT) is specifically responsible for monitoring and managing security of the enterprise IT and OT network and systems, including developing and deploying administrative policies, technical controls, and safety protocols necessary to prevent unauthorized access, theft, damage, or loss of Company data or systems. All members of the MCT hold globally-recognized security certifications and have wide-ranging experience in cybersecurity matters.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	All members of the MCT hold globally-recognized security certifications and have wide-ranging experience in cybersecurity matters.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Cybersecurity Team (MCT) is specifically responsible for monitoring and managing security of the enterprise IT and OT network and systems, including developing and deploying administrative policies, technical controls, and safety protocols necessary to prevent unauthorized access, theft, damage, or loss of Company data or systems.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Significant Accounting Polices

Significant Accounting Polices (Policies)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries and are presented in conformity with GAAP.
Principles of Consolidation	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. 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 and NGLs 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, 2024 and 2023, 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, 2024 and 2023, 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 including 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 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. 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 arising from 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 it may 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 risk management objectives and strategy. 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) with market based conditions, and expense is recognized over the three-year vesting period. The fair value of PSUs with performance-based conditions and time-based restricted stock units (RSUs) is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two
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 net 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 Reportable Segment Disclosures. In November 2023, the FASB issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . 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 Company adopted this standard in the fourth quarter of 2024. The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note S . Recent Accounting Pronouncements Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. Income Tax Disclosures. In December 2023, the FASB issued 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. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The Company’s revenues and other income for each of the three years presented were as follows. Years Ended December 31, (Thousands of dollars) 2024 2023 2022 Net crude oil and condensate revenue United States - Onshore $ 586,584 $ 676,139 $ 856,219 United States - Offshore 1 1,777,723 2,072,353 2,229,658 Canada - Onshore 70,855 78,088 131,400 Canada - Offshore 193,961 78,650 117,747 Other 6,537 11,022 22,824 Total crude oil and condensate revenue 2,635,660 2,916,252 3,357,848 Net natural gas liquids revenue United States - Onshore 32,853 33,178 64,015 United States - Offshore 1 38,858 47,434 60,424 Canada - Onshore 7,454 8,914 18,338 Total natural gas liquids revenue 79,165 89,526 142,777 Net natural gas revenue United States - Onshore 17,443 21,346 64,037 United States - Offshore 1 50,329 71,332 161,160 Canada - Onshore 232,259 278,183 312,629 Total natural gas revenue 300,031 370,861 537,826 Revenue from production 3,014,856 3,376,639 4,038,451 Sales of purchased natural gas 2 United States - Offshore — — 204 Canada - Onshore 3,742 72,215 181,485 Total sales of purchased natural gas 3,742 72,215 181,689 Total revenue from sales to customers 3,018,598 3,448,854 4,220,140 (Loss) on derivative instruments (1,707) — (320,410) Gain on sale of assets and other operating income 11,583 11,293 32,932 Total revenues and other income $ 3,028,474 $ 3,460,147 $ 3,932,662 1 Includes revenue attributable to noncontrolling interest in MP GOM. 2
Schedule of Current Long-Term Contracts Outstanding	As of December 31, 2024, 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, 2024 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGLs Q2 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 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 Canada Natural Gas Q4 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCFD Canada NGLs Q2 2025 Contracts to sell NGLs at CAD index pricing As produced

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 21,716,358 $ 8,021,620 2 $ 21,228,490 $ 8,201,475 2 Corporate and other 149,834 33,033 132,092 23,722 Property, plant and equipment $ 21,866,192 $ 8,054,653 $ 21,360,582 $ 8,225,197 ¹ Includes unproved mineral rights as follows: $ 283,015 $ 151,341 $ 351,000 $ 228,329 2 Includes $13,335 in 2024 and $15,356 in 2023 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) 2024 2023 2022 United States - Offshore $ 62,909 $ — $ — $ 62,909 $ — $ —
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 ) 2024 2023 2022 Beginning balance at January 1 $ 49,118 $ 171,860 $ 179,481 Additions pending the determination of proved reserves 49,408 48 33,440 Reclassifications to proved properties based on the determination of proved reserves — (82,185) — Divestment — — (7,915) Capitalized exploration well costs charged to expense (26,471) (40,605) (33,146) Ending balance at December 31 $ 72,055 $ 49,118 $ 171,860
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging	The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well. 2024 2023 2022 ( Thousands of dollars ) Amount No. of Amount No. of Amount No. of Aging of capitalized well costs Zero to one year $ 49,790 5 $ — — $ 15,527 2 One to two years — — — — 13,307 2 Two to three years — — 2,698 1 — — Three years or more 22,265 3 46,420 3 143,026 5 $ 72,055 8 $ 49,118 4 $ 171,860 9

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2024
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventories consisted of the following for the respective periods presented: December 31, ( Thousands of dollars ) 2024 2023 Unsold crude oil $ 18,745 $ 10,304 Materials and supplies 36,113 44,150 Inventories $ 54,858 $ 54,454

Financing Arrangements and De_2

Financing Arrangements and Debt (Tables)	12 Months Ended
	Dec. 31, 2024
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) 2024 2023 Notes payable 5.875% notes, due December 2027 $ 78,899 $ 443,249 6.375% notes, due July 2028 148,590 372,226 7.05% notes, due May 2029 117,582 179,708 6.00% notes, due October 2032 600,000 — 5.875% notes, due December 2042 ¹ 339,761 339,761 Total notes payable 1,284,832 1,334,944 Unamortized debt issuance cost and discount on notes payable (14,336) (10,107) Total notes payable, net of unamortized discount 1,270,496 1,324,837 Finance lease obligations, due through November 2034 4,877 4,238 Total debt including current maturities 1,275,373 1,329,075 Current maturities (871) (723) Total long-term debt $ 1,274,502 $ 1,328,352 1

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
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) 2024 2023 Balance at beginning of year $ 914,763 $ 911,653 Accretion 52,511 46,059 Liabilities incurred 25,619 20,628 Revisions of previous estimates 29,279 29,056 Liabilities settled (1,898) (95,637) Changes due to translation of foreign currencies (11,390) 3,004 Balance at end of period 1,008,884 914,763 Current portion of liability (48,080) (10,712) Non-current portion of liability $ 960,804 $ 904,051

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
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 ) 2024 2023 2022 Income (loss) from continuing operations before income taxes United States $ 468,202 $ 901,761 $ 1,306,200 Foreign 99,367 19,308 144,061 Total $ 567,569 $ 921,069 $ 1,450,261 Income tax expense (benefit) U.S. Federal – Current $ — $ — $ — – Deferred 55,377 170,115 234,749 Total U.S. Federal 55,377 170,115 234,749 State (4,488) 6,622 9,010 Foreign – Current 4,685 13,182 18,134 – Deferred 22,698 6,002 47,571 Total Foreign 27,383 19,184 65,705 Total $ 78,272 $ 195,921 $ 309,464
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 ) 2024 2023 2022 Income tax expense based on the U.S. statutory tax rate $ 119,190 $ 193,424 $ 304,555 Foreign income subject to foreign tax rates different than the U.S. statutory rate 12,119 7,597 10,823 State income taxes, net of federal benefit (3,568) 4,725 7,118 U.S. tax benefit on certain foreign upstream investments (33,677) — — Change in deferred tax asset valuation allowance related to other foreign exploration expenditures 2,636 10,853 24,748 Tax effect on income attributable to noncontrolling interest (16,656) (13,046) (36,471) Other, net (1,772) (7,632) (1,309) Total $ 78,272 $ 195,921 $ 309,464
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 ) 2024 2023 Deferred tax assets Property and leasehold costs $ 225,379 $ 240,065 Liabilities for dismantlements 36,719 34,258 Postretirement and other employee benefits 66,293 82,437 U. S. net operating loss 289,594 357,490 Investment in partnership 9,096 14,655 Other deferred tax assets 100,352 48,778 Total gross deferred tax assets 727,433 777,683 Less: Valuation allowance (149,498) (146,861) Net deferred tax assets 577,935 630,822 Deferred tax liabilities Deferred tax on undistributed foreign earnings (5,000) (5,000) Accumulated depreciation, depletion and amortization (811,178) (847,981) Other deferred tax liabilities (97,547) (54,052) Total gross deferred tax liabilities (913,725) (907,033) Net deferred tax (liabilities) assets $ (335,790) $ (276,211)
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 ) 2024 2023 2022 Balance at January 1 $ 6,384 $ 3,928 $ 2,903 Additions for tax positions related to current year 1,643 — 77 Additions for tax positions related to prior year 1,952 2,456 948 Balance at December 31 $ 9,979 $ 6,384 $ 3,928

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2024
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 ) 2024 2023 2022 Compensation charged against income before income tax benefit $ 40,831 $ 58,760 $ 74,587 Related income tax benefit recognized in income 5,513 9,330 12,710
Schedule of Assumptions used in Valuation of Performance Awards Granted	The assumptions used in the valuation of the performance awards granted in 2024, 2023 and 2022 are presented in the following table. 2024 2023 2022 Fair value per share at grant date $41.95 $60.46 $37.77 - $47.37 Assumptions Expected volatility 50.00% 81.00% 79.00% - 81.00% Risk-free interest rate 4.14% 3.90% 1.39% - 2.85% Stock beta 1.062 1.034 1.195 - 1.200 Expected life 3.0 years 3.0 years 3.0 years
Schedule of Changes in PSUs and RSUs Outstanding	The fair value of the PSUs based on ROACE was estimated based on the average high/low price of the Company’s stock on the grant date. Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2024 2023 2022 Outstanding at beginning of year 1,818,188 2,148,467 2,670,756 Granted 536,900 409,160 595,700 Vested and issued (938,599) (408,135) (654,177) Forfeited (24,068) (331,304) (463,812) Outstanding at end of year 1,392,421 1,818,188 2,148,467 Changes in RSUs outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2024 2023 2022 Outstanding at beginning of year 1,219,584 1,227,792 1,451,438 Granted 741,228 556,100 416,492 Vested and issued (330,444) (517,047) (462,418) Forfeited (71,768) (47,261) (177,720) Outstanding at end of year 1,558,600 1,219,584 1,227,792
Schedule of Stock Unit Awards	The fair value of the time-based RSUs awarded for each of the last three years is presented in the following table. Type of Plan Valuation Methodology 2024 2023 2022 Non-Employee Directors 1 Closing Stock Price at Grant Date $30.26 - $45.70 $43.27 $32.84 Long-Term Incentive Plan 2 Average High/Low Stock Price at Grant Date $37.78 - $45.98 $42.20 $29.80 - $49.86 1 Under the 2021 NED Plan, RSUs granted in 2024 are scheduled to vest in February 2025. 2 The RSUs granted under the 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, 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, 2021 1,319,500 34.25 Exercisable at December 31, 2022 13,000 28.51

Employee and Retiree Benefit _2

Employee and Retiree Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2024
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 ) 2024 2023 2024 2023 Change in benefit obligation Obligation at January 1 $ 699,151 $ 663,073 $ 63,808 $ 67,679 Service cost 7,042 6,542 436 495 Interest cost 33,554 34,140 2,923 3,241 Participant contributions — — 2,730 2,629 Actuarial (gain) loss 1 (35,417) 26,625 825 (5,567) Medicare Part D subsidy — — 358 299 Exchange rate changes (3,263) 6,089 (14) 2 Benefits paid (45,743) (56,296) (16,072) (4,970) Plan amendments 2 — 18,978 — — Obligation at December 31 655,324 699,151 54,994 63,808 Change in plan assets Fair value of plan assets at January 1 477,809 450,944 — — Actual return on plan assets 27,317 39,953 — — Employer contributions 35,477 37,546 12,984 2,042 Participant contributions — — 2,730 2,629 Medicare Part D subsidy — — 358 299 Exchange rate changes (2,740) 5,662 — — Benefits paid (45,743) (56,296) (16,072) (4,970) Fair value of plan assets at December 31 492,120 477,809 — — Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 1,819 3,192 — — Other accrued liabilities (10,617) (10,219) (4,237) (4,433) Deferred credits and other liabilities (154,406) (214,315) (50,757) (59,375) Fund Status and net plan liability recognized at December 31 $ (163,204) $ (221,342) $ (54,994) $ (63,808) 1 Actuarial gains in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation. 2 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 ) 2024 2023 2024 2023 Benefit obligation at December 31 $ 115,428 $ 133,822 $ 106 $ 115 Fair value of plan assets at December 31 103,445 119,236 — — Net plan liabilities recognized (11,983) (14,586) (106) (115) Net periodic benefit expense (benefit) 1,480 1,387 (44) (44)
Schedule of Amounts Included in Accumulated Other Comprehensive Loss Not Recognized in Net Periodic Benefit Expense	At December 31, 2024, amounts included in “Accumulated other comprehensive loss” 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) $ (163,218) $ 39,742 Prior service (credit) cost (18,233) 3,405 $ (181,451) $ 43,147
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 ) 2024 2023 2024 2023 2024 2023 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 497,947 $ 534,751 $ 489,225 $ 523,096 $ 477,983 $ 461,363 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 145,058 151,146 143,859 148,661 — — Unfunded other postretirement plans 54,994 63,808 54,994 63,808 — —
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 ) 2024 2023 2022 2024 2023 2022 Service cost $ 7,042 $ 6,542 $ 7,875 $ 436 $ 495 $ 968 Interest cost 33,554 34,140 22,747 2,923 3,241 2,211 Expected return on plan assets (33,427) (32,839) (36,458) — — — Amortization of prior service cost (credit) 2,316 620 (684) (532) (532) (532) Recognized actuarial loss (gain) 9,438 9,776 16,098 (3,586) (3,512) (615) Net periodic benefit expense 18,923 18,239 9,578 (759) (308) 2,032 Other pension costs 251 219 — — — — Total net periodic benefit expense $ 19,174 $ 18,458 $ 9,578 $ (759) $ (308) $ 2,032
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, 2024 and 2023 and net periodic benefit expense for 2024 and 2023. Benefit Obligations Net Periodic Benefit Expense Pension Other Pension Other December 31, December 31, Year Year 2024 2023 2024 2023 2024 2023 2024 2023 Discount rate on obligation, interest cost and service cost 5.58 % 5.03 % 5.65 % 5.15 % 5.17 % 5.27 % 5.15 % 5.41 % Rate of compensation increase 3.38 % 3.52 % — — 3.50 % 3.52 % — — Cash balance interest credit rate 3.20 % 3.20 % — — — — — — Expected return on plan assets — — — — 7.19 % 7.35 % — —
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 2025 $ 49,406 $ 4,237 2026 50,193 4,252 2027 51,634 4,267 2028 51,632 4,386 2029 51,457 4,278 2030-2034 261,891 20,594
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, 2024 2023 Equity securities 57.3 % 62.6 % Fixed income securities 36.2 % 29.1 % Alternatives 3.7 % 5.1 % Cash equivalents 2.8 % 3.2 % 100.0 % 100.0 %
Schedule of Fair Value Measurements of Retirement Plan Assets	At December 31, 2024, 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 $ 87,124 $ 87,124 $ — $ — U.S. small/midcap 51,978 51,978 — — Other alternative strategies 965 — — 965 International equity 22,724 22,724 — — Emerging market equity 7,638 7,638 — — Fixed income securities: U.S. fixed income 208,755 105,302 103,453 — Cash and equivalents 9,491 9,491 — — Total Domestic Plans 388,675 284,256 103,453 965 Foreign Plans Equity securities funds 14,377 — 14,377 — Fixed income securities funds 26,500 — 26,500 — Diversified pooled fund 41,054 — 41,054 — Other 17,049 — — 17,049 Cash and equivalents 4,465 — 4,465 — Total Foreign Plans 103,445 — 86,396 17,049 Total $ 492,120 $ 284,256 $ 189,849 $ 18,014 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
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, 2022 $ 32,734 Actual return on plan assets: Relating to assets held at the reporting date 711 Purchases, sales and settlements (8,991) Total at December 31, 2023 24,454 Actual return on plan assets: Relating to assets held at the reporting date (3,574) Relating to assets sold during the period (2,865) Total at December 31, 2024 $ 18,015

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Price Risk Derivatives	At December 31, 2024 volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 20 $ 3.20 1/1/2025 1/31/2025 Subsequent to year end, the Company entered into additional natural gas derivative contracts. Volumes per day and the weighted average prices for these contracts are as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 40 $ 3.58 2/1/2025 6/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.65 7/1/2025 9/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.74 10/1/2025 12/31/2025
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	At December 31, 2024 and 2023, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. See also Note O . ( Thousands of dollars ) Asset (Liability) Derivatives Fair Value at December 31, Type of Derivative Contract Balance Sheet Location 2024 2023 Commodity swaps Accounts payable $ (1,707) —
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 2024 2023 2022 Commodity swaps Loss on derivative instruments $ (1,707) $ — $ (160,690) Commodity collars Loss on derivative instruments — — (159,721)

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2024
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 ) 2024 2023 2022 Basic method 150,011,458 155,233,560 155,276,533 Dilutive stock options and restricted stock units 1,015,894 1,412,869 2,198,305 Diluted method 151,027,352 156,646,429 157,474,838
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 diluted earnings per share because the incremental shares from the assumed conversion were antidilutive. 2024 2023 2022 Antidilutive stock options excluded from diluted shares — — 126,000 Weighted average price of these options — — $49.65

Other Financial Information (Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2024
Other Financial Information [Abstract]
Schedule of Noncash Operating Working Capital (Increase) Decrease	Supplemental Information to Statement of Cash Flows ( Thousands of dollars ) 2024 2023 2022 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ 71,081 $ 47,151 $ (137,228) (Increase) decrease in inventories 1,327 329 (1,534) (Increase) decrease in prepaid expenses 1,192 (1,293) (3,413) Increase (decrease) in accounts payable and accrued liabilities ¹ 3,287 (140,011) 69,854 Increase (decrease) in income taxes payable (2,004) (5,537) 6,593 Net decrease (increase) in non-cash operating working capital $ 74,883 $ (99,361) $ (65,728) Supplementary disclosures: Cash income taxes paid, net of refunds $ 12,648 $ 12,356 $ 24,853 Interest paid, net of amounts capitalized of $11.4 million in 2024, $14.5 million in 2023 and $16.3 million in 2022 78,806 108,912 149,597 Non-cash investing activities: Asset retirement costs capitalized $ 47,233 $ 32,975 $ (21,147) (Increase) decrease in capital expenditure accrual (5,935) 17,517 (31,397) 1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2024
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Components of Accumulated Other Comprehensive Loss	The components of ”Accumulated other comprehensive loss” 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, 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 36,598 (23,029) 13,569 Balance at December 31, 2023 (381,632) (139,485) (521,117) 2024 components of other comprehensive income (loss): Before reclassifications to income (134,692) 23,713 (110,979) Reclassifications to income — 4,024 ¹ 4,024 Net other comprehensive income (loss) (134,692) 27,737 (106,955) Balance at December 31, 2024 $ (516,324) $ (111,748) $ (628,072) 1 Reclassifications before taxes of $5.4 million and $5.6 million are included in the computation of net periodic benefit expense in 2024 and 2023, respectively. See Note J for additional information. Related income taxes of $1.4 million and $1.1 million are included in income tax expense in 2024 and 2023, respectively.

Assets and Liabilities Measur_2

Assets and Liabilities Measured at Fair Value (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 19,469 $ — $ — $ 19,469 $ 17,785 $ — $ — $ 17,785 Commodity swaps — 1,707 — 1,707 — — — — $ 19,469 $ 1,707 $ — $ 21,176 $ 17,785 $ — $ — $ 17,785
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, 2024 and 2023. 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, 2024 2023 ( Thousands of dollars ) Carrying Fair Carrying Fair Financial liabilities: Current and long-term debt $ 1,275,374 $ 1,185,961 $ 1,329,075 $ 1,265,185
Schedule of Fair Value Measurements, Nonrecurring	The fair value information associated with the impaired properties is presented in the following table: Year Ended December 31, 2024 Net Book Total Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 2024 Assets: Impaired proved properties United States - Offshore $ — — 501 63,410 62,909

Common Stock Issued and Outst_2

Common Stock Issued and Outstanding (Tables)	12 Months Ended
	Dec. 31, 2024
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 ) 2024 2023 2022 Beginning of year 152,748,642 155,467,319 154,463,050 Stock options exercised 1 — 2,657 181,655 Restricted stock awards 1 1,105,268 689,824 822,614 Treasury shares purchased (8,008,786) (3,411,158) — End of year 145,845,124 152,748,642 155,467,319 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
	Dec. 31, 2024
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. 2024 2023 2022 Chevron Corporation 13 % 16 % 19 % ExxonMobil Corporation 20 % 27 % 12 % Phillips 66 10 % N/A N/A
Schedule of Segment Information	Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Other, and Discontinued Operations Consolidated Year ended December 31, 2024 Revenue from production $ 2,503.8 $ 504.5 $ 6.6 $ 3,014.9 $ — $ 3,014.9 Sales of purchased natural gas — 3.7 — 3.7 — 3.7 Gain on sales of assets and other operating income 4.5 1.5 — 6.0 3.9 9.9 Revenues from external customers 2,508.3 509.7 6.6 3,024.6 3.9 3,028.5 Lease operating expenses Lease operating expenses and taxes other than income 471.3 176.8 1.6 649.7 — 649.7 Repair and maintenance 63.7 4.8 — 68.5 — 68.5 Workovers 214.9 3.9 — 218.8 — 218.8 Total lease operating expenses 749.9 185.5 1.6 937.0 — 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 — 3.1 Selling and general expenses (3.3) 20.4 6.7 23.8 89.1 112.9 Exploration Expenses — Geological and geophysical 14.4 0.2 12.6 27.2 — 27.2 Dry holes and previously suspended exploration costs 70.9 — 2.3 73.2 — 73.2 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 10.9 0.3 21.9 33.1 — 33.1 Total exploration expenses 96.2 0.5 36.8 133.5 — 133.5 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 8.9 865.8 Impairment of assets 62.9 — — 62.9 — 62.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 0.1 52.5 Other operating expenses 9.3 2.8 2.1 14.2 (3.2) 11.0 Interest Income (22.0) — — (22.0) (12.2) (34.2) Interest (expense), net of capitalization 0.2 0.4 0.2 0.8 105.1 105.9 Income tax expense Current income tax expense 1.5 3.2 0.2 4.9 0.9 5.8 Deferred income tax expense 123.8 8.8 (31.2) 101.4 (28.9) 72.5 Total income tax expense 125.3 12.0 (31.0) 106.3 (28.0) 78.3 Other segment costs (income) 6.9 0.1 0.3 7.3 (44.0) (36.7) Segment income (loss) - including NCI 1 $ 561.9 $ 49.0 $ (12.5) $ 598.4 $ (111.9) $ 486.5 Additions to property, plant, equipment $ 601.7 $ 137.9 $ 71.8 $ 811.4 $ 29.2 $ 840.6 Total assets at year-end 6,953.8 1,919.8 302.0 9,175.6 491.9 9,667.5 1 Includes results attributable to a noncontrolling interest in MP GOM. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Consolidated Year ended December 31, 2023 Revenue from production $ 2,921.8 $ 443.8 $ 11.0 $ 3,376.6 $ — $ 3,376.6 Sales of purchased natural gas — 72.2 — 72.2 — 72.2 Gain on sales of assets and other operating income 6.5 1.5 — 8.0 3.3 11.3 Revenues from external customers 2,928.3 517.5 11.0 3,456.8 3.3 3,460.1 Lease operating expenses Lease operating expenses and taxes other than income 532.3 144.7 1.9 678.9 — 678.9 Repair and maintenance 53.2 5.0 — 58.2 — 58.2 Workovers 45.2 2.1 — 47.3 — 47.3 Total lease operating expenses 630.7 151.8 1.9 784.4 — 784.4 Severance and ad valorem taxes 41.4 1.4 — 42.8 — 42.8 Transportation, gathering and processing 157.0 76.0 — 233.0 — 233.0 Costs of purchased natural gas — 51.7 — 51.7 — 51.7 Selling and general expenses 11.8 16.5 9.4 37.7 81.2 118.9 Exploration Expenses — Geological and geophysical 6.6 0.1 19.4 26.1 — 26.1 Dry holes and previously suspended exploration costs 153.1 — 16.7 169.8 — 169.8 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 14.9 0.4 23.6 38.9 — 38.9 Total exploration expenses 174.6 0.5 59.7 234.8 — 234.8 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 Other operating expenses Other miscellaneous operating expenses 20.1 15.5 8.1 43.7 (4.4) 39.3 Loss on contingent consideration 7.1 — — 7.1 — 7.1 Total other operating expenses 27.2 15.5 8.1 50.8 (4.4) 46.4 Interest Income (3.3) — — (3.3) (9.3) (12.6) Interest expense, net of capitalization 0.1 0.2 0.2 0.5 111.9 112.4 Income tax expense Current income tax expense 3.1 3.7 0.6 7.4 8.8 16.2 Deferred income tax expense 229.6 7.5 (6.7) 230.4 (50.6) 179.8 Total income tax expense 232.7 11.2 (6.1) 237.8 (41.8) 196.0 Other segment costs (income) 7.2 1.1 0.6 8.9 12.1 21.0 Segment income (loss) - including NCI 1 $ 905.1 $ 41.6 $ (65.5) $ 881.2 $ (157.5) $ 723.7 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 9,400.2 366.5 9,766.7 1 Includes results attributable to a noncontrolling interest in MP GOM. Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total Corporate, Consolidated Year ended December 31, 2022 Revenue from production $ 3,435.5 $ 580.0 $ 23.0 $ 4,038.5 $ — $ 4,038.5 Sales of purchased natural gas 0.2 181.5 — 181.7 — 181.7 Gain on sales of assets and other operating income (loss) 25.5 1.4 — 26.9 (314.4) (287.5) Revenues from external customers 3,461.2 762.9 23.0 4,247.1 (314.4) 3,932.7 Lease operating expenses Lease operating expenses and taxes other than income 458.2 147.9 1.5 607.6 — 607.6 Repair and maintenance 34.9 4.7 — 39.6 — 39.6 Workovers 29.6 2.5 — 32.1 — 32.1 Total lease operating expenses 522.7 155.1 1.5 679.3 — 679.3 Severance and ad valorem taxes 55.7 1.3 — 57.0 — 57.0 Transportation, gathering and processing 142.2 70.5 — 212.7 — 212.7 Costs of purchased natural gas 0.2 171.8 — 172.0 — 172.0 Selling and general expenses 20.4 21.9 2.2 44.5 88.8 133.3 Exploration Expenses — Geological and geophysical 8.3 0.4 1.8 10.5 — 10.5 Dry holes and previously suspended exploration costs 23.0 — 59.1 82.1 — 82.1 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 16.2 0.7 23.7 40.6 — 40.6 Total exploration expenses 47.5 1.1 84.6 133.2 — 133.2 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 Other operating expenses Other miscellaneous operating expenses 41.3 10.5 2.4 54.2 5.0 59.2 Loss on contingent consideration 78.3 — — 78.3 — 78.3 Total other operating expenses 119.6 10.5 2.4 132.5 5.0 137.5 Interest Income (0.3) — — (0.3) (2.5) (2.8) Interest expense, net of capitalization 0.1 — 0.3 0.4 150.4 150.8 Income tax expense Current income tax expense 8.1 8.8 2.3 19.2 4.2 23.4 Deferred income tax expense 362.7 34.8 0.6 398.1 (112.0) 286.1 Total income tax expense 370.8 43.6 2.9 417.3 (107.8) 309.5 Other segment costs (income) 6.9 1.8 0.6 9.3 (20.8) (11.5) Segment income (loss) - including NCI 1 $ 1,521.9 $ 134.2 $ (77.0) $ 1,579.1 $ (440.4) $ 1,138.7 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 1,035.4 10,309.0 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 2024 $ 6,415.9 $ 1,389.5 $ 249.2 $ 8,054.6 2023 6,555.0 1,497.3 172.8 8,225.1 2022 6,562.8 1,499.1 166.1 8,228.0 1 Certain long-lived assets at December 31 represent total non-current assets, excluding investments, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2024
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 2024 2023 Operating lease 1, 2 Lease operating expenses $ 411,303 $ 246,721 Operating lease 2 Transportation, gathering and processing 16,117 37,797 Operating lease 2 Selling and general expenses 10,990 9,859 Operating lease 2 Other operating expense 6,622 675 Operating lease 2 Exploration expenses 38,974 110,577 Operating lease 2 Property, plant and equipment 277,170 204,595 Operating lease 2 Asset retirement obligations 10 57,442 Finance lease Amortization of asset Depreciation, depletion and amortization 855 1,505 Interest on lease liabilities Interest expense, net 193 221 Sublease income Other income (1,143) (1,402) Net lease expense $ 761,091 $ 667,990 1 Variable lease expenses. For the years ended December 31, 2024 and 2023, includes variable lease expenses of $42.3 million and $36.7 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, 2024, includes $236.4 million in lease operating expenses, $13.0 million for “Transportation, gathering and processing”, $38.5 million for “Exploration expenses, including undeveloped lease amortization”, $0.8 million in “Selling and general expenses”, $6.2 million in “Other operating expense”, $97.1 million in “Property, plant and equipment, net” and nil 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, 2023, includes $78.2 million in lease operating expenses, $29.4 million in “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.
Schedule of Maturity of Operating Leases	Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2025 $ 290,474 $ 1,257 $ 291,731 2026 123,487 1,257 124,744 2027 66,521 1,257 67,778 2028 59,398 1,257 60,655 2029 56,849 456 57,305 Remaining 406,450 927 407,377 Total future minimum lease payments 1,003,179 6,411 1,009,590 Less imputed interest (212,590) (1,534) (214,124) Present value of lease liabilities 1 $ 790,589 $ 4,877 $ 795,466 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 2025 $ 290,474 $ 1,257 $ 291,731 2026 123,487 1,257 124,744 2027 66,521 1,257 67,778 2028 59,398 1,257 60,655 2029 56,849 456 57,305 Remaining 406,450 927 407,377 Total future minimum lease payments 1,003,179 6,411 1,009,590 Less imputed interest (212,590) (1,534) (214,124) Present value of lease liabilities 1 $ 790,589 $ 4,877 $ 795,466 1 Includes both the current and long-term portion of the lease liabilities.
Schedule of Other Lease Information	Lease Term and Discount Rate December 31, 2024 December 31, 2023 Weighted average remaining lease term: Operating leases 8 years 10 years Finance leases 6 years 5 years Weighted average discount rate: Operating leases 5.7 % 5.9 % Finance leases 4.9 % 4.7 % Other Information Year Ended December 31, (Thousands of dollars) 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 328,847 $ 271,488 Operating cash flows from finance leases 311 221 Financing cash flows from finance leases 665 622 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 349,312 $ 5,923 1 For the year ended December 31, 2024, right-of-use assets obtained in exchange for lease liabilities primarily includes $254.1 million related to the extension of an operating lease pertaining to a drill ship used in our U.S. Offshore business and $52.7 million pertaining to two drilling rigs and several natural gas compressor units at our U.S. Onshore business. December 31, 2023 includes $4.5 million related to natural gas compressor units at various U.S. Onshore locations.

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2024
Oil and Gas Disclosure [Abstract]
Schedule 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, 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 — — Sale 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 Sale of properties (5.2) — (5.2) — Production (70.4) (45.3) (25.0) (0.1) December 31, 2023 739.5 311.1 415.5 12.9 Revisions of previous estimates 14.3 8.1 6.3 (0.1) Improved recovery 11.3 11.3 — — Extensions and discoveries 31.4 16.0 15.4 — Production (67.5) (39.1) (28.3) (0.1) December 31, 2024 ¹ 729.0 307.4 408.9 12.7 Proved developed reserves: 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 425.5 223.2 202.0 0.3 December 31, 2024 ² 436.2 218.9 217.1 0.2 Proved undeveloped reserves: 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 314.0 87.9 213.5 12.6 December 31, 2024 ³ 292.8 88.5 191.8 12.5 1 Total and United States includes proved reserves of 15.9 MMBOE, consisting of 14.5 MMBBL of oil, 0.6 MMBBL of NGLs and 5 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 14.4 MMBOE, consisting of 13.2 MMBBL of oil, 0.5 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.5 MMBOE, consisting of 1.3 MMBBL of oil, 0.1 MMBBL of NGLs and 0.8 BCF of 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, 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 — — Sale 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 Sale of properties (2.0) — (2.0) — Production (37.9) (35.6) (2.2) (0.1) December 31, 2023 275.8 228.0 35.4 12.4 Revisions of previous estimates 6.6 6.6 0.1 (0.1) Improved recovery 10.7 10.7 — — Extensions and discoveries 16.6 10.7 5.9 — Production (34.6) (30.8) (3.7) (0.1) December 31, 2024 ¹ 275.1 225.2 37.7 12.2 Proved developed crude oil reserves: 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 186.3 163.7 22.3 0.3 December 31, 2024 ² 184.7 164.1 20.4 0.2 Proved undeveloped crude oil reserves: 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 89.5 64.3 13.1 12.1 December 31, 2024 ³ 90.4 61.1 17.3 12.0 1 Total and United States includes proved reserves of 14.5 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 13.2 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.3 MMBBL 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, 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 — Purchase of properties 0.3 0.3 — — Sale 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 — Sale of properties (0.6) — (0.6) — Production (4.1) (3.8) (0.3) — December 31, 2023 37.6 34.3 3.3 — Revisions of previous estimates 1.2 0.3 0.9 — Improved recovery 0.4 0.4 — — Extensions and discoveries 2.9 2.4 0.5 — Production (3.5) (3.3) (0.2) — December 31, 2024 ¹ 38.6 34.1 4.5 — Proved developed NGL reserves: December 31, 2021 28.4 25.6 2.8 — December 31, 2022 29.7 27.4 2.3 — December 31, 2023 25.9 24.1 1.8 — December 31, 2024 ² 24.1 21.9 2.2 — Proved undeveloped NGL reserves: December 31, 2021 10.0 9.5 0.5 — December 31, 2022 12.0 10.2 1.8 — December 31, 2023 11.7 10.2 1.5 — December 31, 2024 ³ 14.5 12.2 2.3 — 1 Total and United States includes total proved reserves of 0.6 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 0.5 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.1 MMBBL 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, 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 Sale of properties (15.6) — (15.6) — Production (170.1) (35.1) (135.0) — December 31, 2023 2,556.2 293.1 2,260.1 3.0 Revisions of previous estimates 39.1 7.7 31.4 — Improved recovery 1.2 1.2 — — Extensions and discoveries 71.4 17.0 54.4 — Production (176.1) (30.1) (146.0) — December 31, 2024 1,4 2,491.8 288.9 2,199.9 3.0 Proved developed natural gas reserves: 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 1,279.3 212.4 1,066.7 0.2 December 31, 2024 2,4 1,364.2 196.8 1,167.2 0.2 Proved undeveloped natural gas reserves: December 31, 2021 1,126.4 72.2 1,054.1 — December 31, 2022 1,036.8 80.8 956.0 — December 31, 2023 1,276.9 80.7 1,193.4 2.8 December 31, 2024 ³ 1,127.6 92.1 1,032.7 2.8 1 Total and United States includes total proved reserves of 5.0 BCF attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.8 BCF attributable to the noncontrolling interest in MP GOM. 4 Includes proved natural gas reserves to be consumed in operations as fuel of 67.9 BCF, 36.0 BCF and 2.8 BCF for the U.S., Canada and Other, respectively, with 1.1 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 Other Total Year ended December 31, 2024 Property acquisition costs Unproved $ 7.8 $ 0.2 $ — $ 8.0 Proved — — — — Total acquisition costs 7.8 0.2 — 8.0 Exploration costs 85.3 0.4 60.2 145.9 Development costs 598.7 137.7 45.1 781.5 Total costs incurred 691.8 138.3 105.3 935.4 Charged to expense Dry hole expense 70.9 — 2.3 73.2 Geophysical and other costs 19.2 0.4 31.2 50.8 Total charged to expense 90.1 0.4 33.5 124.0 Property additions $ 601.7 $ 137.9 $ 71.8 $ 811.4 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
Schedule of Results of Operations for Oil and Gas Producing Activities	( Millions of dollars ) United Canada Other Total Year ended December 31, 2024 Revenues Crude oil and natural gas liquids sales $ 2,436.0 $ 272.3 $ 6.6 $ 2,714.9 Natural gas sales 67.8 232.2 — 300.0 Sales of purchased natural gas — 3.7 — 3.7 Total oil and natural gas revenues 2,503.8 508.2 6.6 3,018.6 Other operating revenues 4.5 1.5 6.0 Total revenues 2,508.3 509.7 6.6 3,024.5 Costs and expenses Lease operating expenses 749.9 185.5 1.6 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 Exploration costs charged to expense 90.0 0.4 33.5 123.9 Undeveloped lease amortization 6.2 0.1 3.3 9.6 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 Impairment of assets 62.9 — — 62.9 Selling and general expenses (3.3) 20.4 6.7 23.8 Other expenses (benefits) (5.6) 3.3 2.6 0.3 Total costs and expenses 1,821.1 448.7 50.1 2,319.9 Results of operations before taxes 687.2 61.0 (43.5) 704.6 Income tax expense (benefit) 125.3 12.0 (31.0) 106.3 Results of operations $ 561.9 $ 49.0 $ (12.5) $ 598.4 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 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 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, 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.
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, 2024 Future cash inflows $ 18,118.1 $ 6,304.4 $ 1,012.9 $ 25,435.4 Future development costs (2,024.9) (825.9) (252.5) (3,103.3) Future production costs (7,645.7) (4,026.5) (341.7) (12,013.9) Future income taxes (893.5) (251.2) (203.4) (1,348.1) Future net cash flows 7,554.0 1,200.8 215.3 8,970.1 10% annual discount for estimated timing of cash flows (2,887.3) (486.0) (200.9) (3,574.2) Standardized measure of discounted future net cash flows $ 4,666.7 $ 714.8 $ 14.4 $ 5,395.9 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 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 ( Millions of dollars ) 2024 2023 2022 Net changes in prices and production costs 2 $ (1,116.5) $ (5,845.6) $ 4,812.2 Net changes in development costs (152.7) (78.8) (531.1) Sales and transfers of oil and natural gas produced, net of production costs (1,824.8) (2,264.8) (2,917.4) Net change due to extensions and discoveries 583.7 770.4 1,223.5 Net change due to purchases and sales of proved reserves — (96.1) 102.1 Development costs incurred 668.6 703.7 769.3 Accretion of discount 773.5 1,393.3 802.6 Revisions of previous quantity estimates (688.1) (771.5) 1,652.9 Net change in income taxes 298.8 1,229.6 (1,399.9) Net (decrease) increase (1,457.5) (4,959.8) 4,514.2 Standardized measure at January 1 6,853.4 11,813.2 7,299.0 Standardized measure at December 31 $ 5,395.9 $ 6,853.4 $ 11,813.2 1 Includes noncontrolling interest in MP GOM. 2 The average prices used for 2024 were $75.48 per BBL for NYMEX crude oil (WTI) and $2.13 per MCF for natural gas (Henry Hub). The average prices used for 2023 were $78.22 per BBL 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 BBL for NYMEX crude oil (WTI) and $6.36 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, 2024 Unproved oil and natural gas properties 1 $ 247.3 $ 6.6 $ 29.1 $ 283.0 Proved oil and natural gas properties 16,598.8 4,498.1 246.7 21,343.6 Gross capitalized costs 16,846.1 4,504.7 275.8 21,626.6 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties (111.0) — (20.7) (131.7) Proved oil and natural gas properties (10,326.2) (3,116.2) (44.2) (13,486.6) Net capitalized costs $ 6,408.9 $ 1,388.5 $ 210.9 $ 8,008.3 December 31, 2023 Unproved oil and natural gas properties 1 $ 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 1 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 Inform_2

Supplemental Quarterly Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 Revenue from contracts with customers $ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6 Income from continuing operations before income taxes 145.6 189.6 153.8 78.6 567.6 Income from continuing operations 115.5 156.9 151.7 65.2 489.3 Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5 Net income attributable to Murphy 90.0 127.7 139.1 50.3 407.1 Income from continuing operations per common share ² Basic 0.60 0.84 0.93 0.35 2.73 Diluted 0.60 0.83 0.93 0.34 2.72 Net income per common share ² Basic 0.59 0.84 0.93 0.35 2.71 Diluted 0.59 0.83 0.93 0.34 2.70 Cash dividend per common share 0.300 0.300 0.300 0.300 1.200 Year ended December 31, 2023 Revenue from contracts with customers $ 840.0 $ 812.9 $ 953.8 $ 842.2 $ 3,448.9 Income from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0 Income from continuing operations 214.0 92.5 278.2 140.5 725.2 Net income including noncontrolling interest 214.3 91.9 277.8 139.7 723.7 Net income attributable to Murphy 191.6 98.3 255.3 116.4 661.6 Income 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 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 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) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Significant Accounting Policies [Line Items]
Impairment of assets	$ 62.9
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, 2024 USD ($) segment revenueStream	Dec. 31, 2023 USD ($)
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 | $	$ 178.3	$ 193.7

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 669,600	$ 753,200	$ 801,000	$ 794,800	$ 842,200	$ 953,800	$ 812,900	$ 840,000	$ 3,018,598	$ 3,448,854	$ 4,220,140
(Loss) on derivative instruments									(1,707)	0	(320,410)
Gain on sale of assets and other operating income									11,583	11,293	32,932
Total revenues and other income									3,028,474	3,460,147	3,932,662
Revenue from production
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									3,014,856	3,376,639	4,038,451
Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									2,635,660	2,916,252	3,357,848
Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									79,165	89,526	142,777
Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									300,031	370,861	537,826
Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									3,742	72,215	181,689
United States - Onshore | Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									586,584	676,139	856,219
United States - Onshore | Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									32,853	33,178	64,015
United States - Onshore | Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									17,443	21,346	64,037
United States Offshore | Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									1,777,723	2,072,353	2,229,658
United States Offshore | Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									38,858	47,434	60,424
United States Offshore | Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									50,329	71,332	161,160
United States Offshore | Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									0	0	204
Canada - Onshore | Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									70,855	78,088	131,400
Canada - Onshore | Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									7,454	8,914	18,338
Canada - Onshore | Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									232,259	278,183	312,629
Canada - Onshore | Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									3,742	72,215	181,485
Canada Offshore | Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									193,961	78,650	117,747
Other | Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									$ 6,537	$ 11,022	$ 22,824

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Schedule of Current Long-Term Contracts Outstanding (Details) - Canada - Contracts to sell natural gas at USD index pricing	Dec. 31, 2024 MMcf
End Date, Quarter 4, 2025
Disaggregation of Revenue [Line Items]
Approximate Volumes	25
End Date Quarter4 , 2026
Disaggregation of Revenue [Line Items]
Approximate Volumes	49
End Date Quarter4 2027
Disaggregation of Revenue [Line Items]
Approximate Volumes	30
End Date Quarter4 2028
Disaggregation of Revenue [Line Items]
Approximate Volumes	10
End Date, Quarter 4, 2025 No.2
Disaggregation of Revenue [Line Items]
Approximate Volumes	40
End Date, Quarter 4, 2026 No.2
Disaggregation of Revenue [Line Items]
Approximate Volumes	50

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Cost	$ 21,866,192	$ 21,360,582
Net	8,054,653	8,225,197
Exploration and Production
Property, Plant and Equipment [Line Items]
Cost	21,716,358	21,228,490
Net	8,021,620	8,201,475
Corporate and other
Property, Plant and Equipment [Line Items]
Cost	149,834	132,092
Net	33,033	23,722
Mineral Rights
Property, Plant and Equipment [Line Items]
Cost	283,015	351,000
Net	151,341	228,329
Administrative Assets and Support Equipment
Property, Plant and Equipment [Line Items]
Net	$ 13,335	$ 15,356

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 ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2024 USD ($)	Mar. 31, 2024 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Property, Plant and Equipment [Line Items]
Impairment of assets								$ 62,900,000
Impairment of assets					$ 28,400,000	$ 34,500,000		62,909,000	$ 0	$ 0
Total capitalized exploratory well costs					72,055,000			72,055,000	49,118,000	171,860,000	$ 179,481,000
Additions pending the determination of proved reserves								49,408,000	48,000	33,440,000
Capitalized exploration well costs charged to expense								26,471,000	40,605,000	$ 33,146,000
Well costs incurred and expensed								46,700,000	129,200,000
Exploratory well costs capitalized more than one year					22,300,000			22,300,000
Mississippi Canyon 216
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed								27,600,000
Mississippi Canyon 387
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed								26,100,000
Walker Ridge 425
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed									82,000,000
Atwater Valley 138
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed									$ 47,200,000
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
Exploratory well costs capitalized more than one year					4,400,000			4,400,000
Vietnam
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year					15,100,000			15,100,000
Brunei
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year					$ 2,700,000			$ 2,700,000

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Recognized Impairments (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2024	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Impairment of assets	$ 28,400,000	$ 34,500,000	$ 62,909,000	$ 0	$ 0
United States Offshore
Property, Plant and Equipment [Line Items]
Impairment of assets			$ 62,909,000	$ 0	$ 0

Property, Plant And Equipment_4

Property, Plant And Equipment - Schedule of Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Capitalized Exploratory Well Cost [Roll Forward]
Beginning balance at January 1	$ 49,118	$ 171,860	$ 179,481
Additions pending the determination of proved reserves	49,408	48	33,440
Reclassifications to proved properties based on the determination of proved reserves / Divestment		(82,185)	(7,915)
Capitalized exploration well costs charged to expense	(26,471)	(40,605)	(33,146)
Ending balance at December 31	$ 72,055	$ 49,118	$ 171,860

Property, Plant And Equipment_5

Property, Plant And Equipment - Schedule of Aging of Capitalized Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2024 USD ($) well	Dec. 31, 2023 USD ($) well	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($)
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount | $	$ 72,055	$ 49,118	$ 171,860	$ 179,481
No. of Wells (in wells) | well	8	4	9
Zero to one year
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount | $	$ 49,790	$ 0	$ 15,527
No. of Wells (in wells) | well	5	0	2
One to two years
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount | $	$ 0	$ 0	$ 13,307
No. of Wells (in wells) | well	0	0	2
Two to three years
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount | $	$ 0	$ 2,698	$ 0
No. of Wells (in wells) | well	0	1	0
Three years or more
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount | $	$ 22,265	$ 46,420	$ 143,026
No. of Wells (in wells) | well	3	3	5

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Inventory Disclosure [Abstract]
Unsold crude oil	$ 18,745	$ 10,304
Materials and supplies	36,113	44,150
Inventories	$ 54,858	$ 54,454

Financing Arrangements and De_3

Financing Arrangements and Debt - Schedule of Long Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Total notes payable	$ 1,284,832	$ 1,334,944
Unamortized debt issuance cost and discount on notes payable	(14,336)	(10,107)
Total notes payable, net of unamortized discount	1,270,496	1,324,837
Finance lease obligations, due through November 2034	4,877	4,238
Debt and Lease Obligation, Total	1,275,373	1,329,075
Current maturities	(871)	(723)
Long-term debt, including finance lease obligation	$ 1,274,502	$ 1,328,352
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation
5.875% notes, due December 2027
Debt Instrument [Line Items]
Total notes payable	$ 78,899	$ 443,249
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	$ 148,590	372,226
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	$ 117,582	179,708
7.05% notes, due May 2029 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.05%
6.00% notes, due October 2032 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6%
Total notes payable	$ 600,000	0
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				3 Months Ended	12 Months Ended
	Oct. 31, 2024 USD ($)	May 31, 2024 USD ($)	Nov. 30, 2023 USD ($)	Sep. 30, 2023 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($) consecutiveTradingDay	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Oct. 03, 2024 USD ($)	Sep. 19, 2024
Debt Instrument [Line Items]
Future maturities of long term debt in 2024					$ 0	$ 0
Future maturities of long term debt in 2025					0	0
Future maturities of long term debt in 2026					78,900,000	78,900,000
Future maturities of long term debt in 2027					148,600,000	148,600,000
Future maturities of long term debt in 2028					117,600,000	117,600,000
Future maturities of long term debt, thereafter					939,800,000	939,800,000
Debt extinguishment cost						15,700,000	$ 0	$ 8,295,000
Senior Notes
Debt Instrument [Line Items]
Repurchase amount	$ 521,100,000	$ 50,500,000	$ 249,500,000
Non - cash debt extinguishment				$ 900,000
Extinguishment of debt			250,000,000
Senior Notes | 6.000 Notes Due 2032
Debt Instrument [Line Items]
Transaction costs									$ 10,100,000
Debt instrument, face amount									$ 600,000,000
Stated interest rate										6%
Senior Notes | 5.875 Notes Due 2027
Debt Instrument [Line Items]
Repurchase amount	258,800,000	26,500,000			79,000,000	79,000,000
Cost of debt extinguishment	18,200,000					1,200,000
Debt extinguishment cost						800,000
Non - cash debt extinguishment	3,300,000					400,000
Additional cash cost	14,900,000
Senior Notes | 6.375 Notes Due 2028
Debt Instrument [Line Items]
Repurchase amount		23,500,000
Extinguishment of debt	200,200,000
Senior Notes | 7.050 Notes Due 2027, 2028
Debt Instrument [Line Items]
Extinguishment of debt	$ 62,100,000
Senior Notes | 2027 and 2028 Notes
Debt Instrument [Line Items]
Cost of debt extinguishment		900,000
Debt extinguishment cost		500,000
Non - cash debt extinguishment		$ 400,000
Senior Notes | 2027 ,2028 and 2029 Notes
Debt Instrument [Line Items]
Cost of debt extinguishment			$ 1,300,000
Additional cash cost						0
Senior Notes | 5.75% Notes Due 2025
Debt Instrument [Line Items]
Repurchase amount				$ 248,700,000
Revolving Credit Facility
Debt Instrument [Line Items]
Transaction costs					14,700,000	14,700,000
Amount outstanding					$ 0	$ 0
Interest rate on credit facility						6.68%
Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Stated interest rate					0.50%	0.50%
Revolving Credit Facility | Unsecured Debt
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity					$ 1,350,000,000	$ 1,350,000,000
Debt instrument, consolidated total capitalization percentage						60%
Debt instrument, period of adjusted SOFR published | consecutiveTradingDay						2
Revolving Credit Facility | Unsecured Debt | Adjusted Term SOFR Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						1%
Revolving Credit Facility | Unsecured Debt | Adjusted Daily Simple SOFR Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						0.10%
Revolving Credit Facility | Unsecured Debt | Daily Simple SOFR
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						0.10%
Revolving Credit Facility | Unsecured Debt | Maximum
Debt Instrument [Line Items]
Debt instrument, consolidated leverage ratio					3.25
Revolving Credit Facility | Unsecured Debt | Minimum
Debt Instrument [Line Items]
Debt instrument, consolidated interest coverage ratio						2.50
Revolving Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Amount outstanding					$ 400,000	$ 400,000

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 914,763	$ 911,653
Accretion	52,511	46,059	$ 46,243
Liabilities incurred	25,619	20,628
Revisions of previous estimates	29,279	29,056
Liabilities settled	(1,898)	(95,637)
Changes due to translation of foreign currencies	(11,390)	3,004
Balance at end of period	$ 1,008,884	$ 914,763	$ 911,653

Asset Retirement Obligations _2

Asset Retirement Obligations - Schedule of Classification of Asset of Asset Retirement Obligations (Details) - USD ($) $ in Thousands		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Balance at end of period		$ 1,008,884	$ 914,763	$ 911,653
Current portion of liability at end of year	[1]	(48,080)	(10,712)
Asset retirement obligations		$ 960,804	$ 904,051
[1] The prior-period amount has been reclassified to conform to the current period presentation.

Income Taxes - Schedule of Comp

Income Taxes - Schedule of 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, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income (loss) from continuing operations before income taxes
United States									$ 468,202	$ 901,761	$ 1,306,200
Foreign									99,367	19,308	144,061
Income from continuing operations before income taxes	$ 78,600	$ 153,800	$ 189,600	$ 145,600	$ 169,500	$ 356,300	$ 127,300	$ 267,900	567,569	921,069	1,450,261
Income tax expense (benefit)
U.S. Federal – Current									0	0	0
Federal - Deferred									55,377	170,115	234,749
Total U.S. Federal									55,377	170,115	234,749
State									(4,488)	6,622	9,010
Foreign – Current									4,685	13,182	18,134
Foreign - Deferred									22,698	6,002	47,571
Total Foreign									27,383	19,184	65,705
Total income tax expense (benefit)									$ 78,272	$ 195,921	$ 309,464

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income tax expense based on the U.S. statutory tax rate	$ 119,190	$ 193,424	$ 304,555
Foreign income subject to foreign tax rates different than the U.S. statutory rate	12,119	7,597	10,823
State income taxes, net of federal benefit	(3,568)	4,725	7,118
U.S. tax benefit on certain foreign upstream investments	(33,677)	0	0
Change in deferred tax asset valuation allowance related to other foreign exploration expenditures	2,636	10,853	24,748
Tax effect on income attributable to noncontrolling interest	(16,656)	(13,046)	(36,471)
Other, net	(1,772)	(7,632)	(1,309)
Total income tax expense (benefit)	$ 78,272	$ 195,921	$ 309,464

Income Taxes - Schedule of Anal

Income Taxes - Schedule of Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Deferred tax assets
Property and leasehold costs	$ 225,379	$ 240,065
Liabilities for dismantlements	36,719	34,258
Postretirement and other employee benefits	66,293	82,437
U. S. net operating loss	289,594	357,490
Investment in partnership	9,096	14,655
Other deferred tax assets	100,352	48,778
Total gross deferred tax assets	727,433	777,683
Less: Valuation allowance	(149,498)	(146,861)
Net deferred tax assets	577,935	630,822
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)	(5,000)
Accumulated depreciation, depletion and amortization	(811,178)	(847,981)
Other deferred tax liabilities	(97,547)	(54,052)
Total gross deferred tax liabilities	(913,725)	(907,033)
Net deferred tax (liabilities) assets	$ (335,790)	$ (276,211)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Line Items]
Increase (decrease) in deferred tax asset valuation allowance	$ 2,600
U. S. net operating loss	289,594	$ 357,490
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	$ 1,400,000

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Unrecognized Tax Benefits [Roll Forward]
Balance at January 1	$ 6,384	$ 3,928	$ 2,903
Additions for tax positions related to current year	1,643	0	77
Additions for tax positions related to prior year	1,952	2,456	948
Balance at December 31	$ 9,979	$ 6,384	$ 3,928

Incentive Plans - Narrative (De

Incentive Plans - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed	$ 46.9
Settlement period of phantom units	3 years
Option term	7 years
Cash settled awards	$ 1.7	$ 29.4	$ 49.3
Incentive compensation plan expense	$ 37.1	$ 30.9	$ 42.9
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)	1,200,000
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, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Compensation charged against income before income tax benefit	$ 40,831	$ 58,760	$ 74,587
Related income tax benefit recognized in income	$ 5,513	$ 9,330	$ 12,710

Incentive Plans - Assumptions u

Incentive Plans - Assumptions used in Valuation Performance Awards Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility rate, minimum			79%
Expected volatility rate, maximum			81%
Risk-free interest rate, minimum			1.39%
Risk-free interest rate, maximum			2.85%
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)	$ 41.95	$ 60.46
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility	50%
Expected volatility rate, minimum		81%
Risk-free interest rate	4.14%	3.90%
Stock beta	1.062	1.034
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]
Stock beta			1.195
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)			$ 47.37
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock beta			1.200
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 | Non-employee | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	$ 30.26
Time lapse restricted stock | Non-employee | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	45.70
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
Time lapse restricted stock | Long Term Incentive Plan | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	37.78	29.80
Time lapse restricted stock | Long Term Incentive Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	$ 45.98	$ 49.86

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	1,818,188	2,148,467	2,670,756
Granted (in shares)	536,900	409,160	595,700
Vested and issued (in shares)	(938,599)	(408,135)	(654,177)
Forfeited (in shares)	(24,068)	(331,304)	(463,812)
Outstanding at end of year (in shares)	1,392,421	1,818,188	2,148,467

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	1,219,584	1,227,792	1,451,438
Granted (in shares)	741,228	556,100	416,492
Vested and issued (in shares)	(330,444)	(517,047)	(462,418)
Forfeited (in shares)	(71,768)	(47,261)	(177,720)
Outstanding at end of year (in shares)	1,558,600	1,219,584	1,227,792

Incentive Plans - Changes in St

Incentive Plans - Changes in Stock Options Outstanding (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Shares
Exercised (in shares)	0	(2,657)	(181,655)
Stock Options
Number of Shares
Outstanding at beginning of year (in shares)	0	13,000	1,319,500
Exercised (in shares)		(11,000)	(760,500)
Forfeited (in shares)		(2,000)	(546,000)
Outstanding at end of year (in shares)		0	13,000
Exercisable at end of year (in shares)			13,000	1,319,500
Average Exercise Price
Outstanding at beginning of year (in USD per share)	$ 0	$ 28.51	$ 37.77
Exercised (in USD per share)		28.51	23.29
Forfeited (in USD per share)		28.51	49.65
Outstanding at end of year (in USD per share)		$ 0	28.51
Exercisable at end of year (in USD per share)			$ 28.51	$ 34.25

Employee and Retiree Benefit _3

Employee and Retiree Benefit Plans - Schedule of Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Change in plan assets
Beginning balance	$ 477,809
Ending balance	492,120	$ 477,809
Pension Benefits
Change in benefit obligation
Beginning balance	699,151	663,073
Service cost	7,042	6,542	$ 7,875
Interest cost	33,554	34,140	22,747
Participant contributions	0	0
Actuarial (gain) loss	(35,417)	26,625
Medicare Part D subsidy	0	0
Exchange rate changes	(3,263)	6,089
Benefits paid	(45,743)	(56,296)
Plan amendments	0	18,978
Ending balance	655,324	699,151	663,073
Change in plan assets
Beginning balance	477,809	450,944
Actual return on plan assets	27,317	39,953
Employer contributions	35,477	37,546
Participant contributions	0	0
Medicare Part D subsidy	0	0
Exchange rate changes	(2,740)	5,662
Benefits paid	(45,743)	(56,296)
Ending balance	492,120	477,809	450,944
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	1,819	3,192
Other accrued liabilities	(10,617)	(10,219)
Deferred credits and other liabilities	(154,406)	(214,315)
Funded status and net plan liability recognized at December 31	(163,204)	(221,342)
Other Postretirement Benefits
Change in benefit obligation
Beginning balance	63,808	67,679
Service cost	436	495	968
Interest cost	2,923	3,241	2,211
Participant contributions	2,730	2,629
Actuarial (gain) loss	825	(5,567)
Medicare Part D subsidy	358	299
Exchange rate changes	(14)	2
Benefits paid	(16,072)	(4,970)
Plan amendments	0	0
Ending balance	54,994	63,808	67,679
Change in plan assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	12,984	2,042
Participant contributions	2,730	2,629
Medicare Part D subsidy	358	299
Exchange rate changes	0	0
Benefits paid	(16,072)	(4,970)
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	(4,237)	(4,433)
Deferred credits and other liabilities	(50,757)	(59,375)
Funded status and net plan liability recognized at December 31	$ (54,994)	$ (63,808)

Employee and Retiree Benefit _4

Employee and Retiree Benefit Plans - Schedule of Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense (Details) $ in Thousands	Dec. 31, 2024 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	$ (163,218)
Prior service (credit) cost	(18,233)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(181,451)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	39,742
Prior service (credit) cost	3,405
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 43,147

Employee and Retiree Benefit _5

Employee and Retiree Benefit Plans - Schedule of Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Funded plan | Qualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 497,947	$ 534,751
Accumulated Benefit Obligations	489,225	523,096
Fair Value of Plan Assets	477,983	461,363
Unfunded plan | Other postretirement plans
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	54,994	63,808
Accumulated Benefit Obligations	54,994	63,808
Fair Value of Plan Assets	0	0
Unfunded plan | Nonqualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	145,058	151,146
Accumulated Benefit Obligations	143,859	148,661
Fair Value of Plan Assets	$ 0	$ 0

Employee and Retiree Benefit _6

Employee and Retiree Benefit Plans - Schedule of Components of Net Periodic Benefit Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7,042	$ 6,542	$ 7,875
Interest cost	33,554	34,140	22,747
Expected return on plan assets	(33,427)	(32,839)	(36,458)
Amortization of prior service cost (credit)	2,316	620	(684)
Recognized actuarial loss (gain)	9,438	9,776	16,098
Net periodic benefit expense	18,923	18,239	9,578
Other pension costs	251	219	0
Total net periodic benefit expense	19,174	18,458	9,578
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	436	495	968
Interest cost	2,923	3,241	2,211
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	(532)	(532)	(532)
Recognized actuarial loss (gain)	(3,586)	(3,512)	(615)
Net periodic benefit expense	(759)	(308)	2,032
Other pension costs	0	0	0
Total net periodic benefit expense	$ (759)	$ (308)	$ 2,032

Employee and Retiree Benefit _7

Employee and Retiree Benefit Plans - Schedule of Amount Related to Foreign Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	$ 492,120	$ 477,809
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	103,445	119,236
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	655,324	699,151	$ 663,073
Fair value of plan assets at December 31	492,120	477,809	450,944
Net plan liabilities recognized	(163,204)	(221,342)
Net periodic benefit expense (benefit)	19,174	18,458	9,578
Pension Benefits | Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	115,428	133,822
Fair value of plan assets at December 31	103,445	119,236
Net plan liabilities recognized	(11,983)	(14,586)
Net periodic benefit expense (benefit)	1,480	1,387
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	54,994	63,808	67,679
Fair value of plan assets at December 31	0	0	0
Net plan liabilities recognized	(54,994)	(63,808)
Net periodic benefit expense (benefit)	(759)	(308)	$ 2,032
Other Postretirement Benefits | Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	106	115
Fair value of plan assets at December 31	0	0
Net plan liabilities recognized	(106)	(115)
Net periodic benefit expense (benefit)	$ (44)	$ (44)

Employee and Retiree Benefit _8

Employee and Retiree Benefit Plans - Schedule of Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.20%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.58%	5.03%
Net periodic benefit expense, discount rate	5.17%	5.27%
Benefit obligation, rate of compensation increase	3.38%	3.52%
Net periodic benefit expense, rate of compensation increase	3.50%	3.52%
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	7.19%	7.35%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.65%	5.15%
Net periodic benefit expense, discount rate	5.15%	5.41%
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, 2024 USD ($) investment	Dec. 31, 2023 USD ($)	Dec. 31, 2022 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	7.50%
Ultimate rate of health care cost	4%
Weighted average expected return on plan asset	7.20%
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	3.30%
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	$ 8,700	$ 8,500	$ 6,000
Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	8%
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	5.20%
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	$ 35,477	$ 37,546
Weighted average expected return on plan asset	7.19%	7.35%
Pension Benefits | United States - Offshore
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	25,600
Pension Benefits | Foreign Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans, next fiscal year	800
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 12,984	$ 2,042
Weighted average expected return on plan asset	0%	0%
Other Postretirement Benefits | United States - Offshore
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 13,000
Contributions to benefit plans, next fiscal year	$ 4,200
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 - Schedule of Benefit Payments Expected to be Paid in Future Years (Details) $ in Thousands	Dec. 31, 2024 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	$ 49,406
2026	50,193
2027	51,634
2028	51,632
2029	51,457
2030-2034	261,891
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	4,237
2026	4,252
2027	4,267
2028	4,386
2029	4,278
2030-2034	$ 20,594

Employee and Retiree Benefit_11

Employee and Retiree Benefit Plans - Schedule of Weighted Average Asset Allocation for Funded Pension Benefit Plans (Details)	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100%	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	57.30%	62.60%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	36.20%	29.10%
Alternatives
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	3.70%	5.10%
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	2.80%	3.20%

Employee and Retiree Benefit_12

Employee and Retiree Benefit Plans - Schedule of Fair Value Measurements of Retirement Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	$ 492,120	$ 477,809
Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	284,256	278,515
Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	189,849	174,841
Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	18,014	24,454
United States - Offshore
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	388,675	358,573
United States - Offshore | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	284,256	278,515
United States - Offshore | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	103,453	76,227
United States - Offshore | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	965	3,831
United States - Offshore | U.S. core equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	87,124	105,212
United States - Offshore | U.S. core equity | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	87,124	105,212
United States - Offshore | U.S. core equity | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | U.S. core equity | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	51,978	64,165
United States - Offshore | U.S. small/midcap | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	51,978	64,165
United States - Offshore | U.S. small/midcap | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | U.S. small/midcap | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Other alternative strategies
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	965	3,831
United States - Offshore | Other alternative strategies | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Other alternative strategies | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Other alternative strategies | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	965	3,831
United States - Offshore | International equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	22,724	31,820
United States - Offshore | International equity | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	22,724	31,820
United States - Offshore | International equity | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | International equity | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Emerging market equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	7,638	10,525
United States - Offshore | Emerging market equity | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	7,638	10,525
United States - Offshore | Emerging market equity | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Emerging market equity | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	208,755	132,608
United States - Offshore | U.S. fixed income | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	105,302	56,381
United States - Offshore | U.S. fixed income | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	103,453	76,227
United States - Offshore | U.S. fixed income | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	9,491	10,412
United States - Offshore | Cash and equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	9,491	10,412
United States - Offshore | Cash and equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States - Offshore | 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	103,445	119,236
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	86,396	98,613
Foreign Plans | Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	17,049	20,623
Foreign Plans | Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	4,465	5,133
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	4,465	5,133
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	14,377	24,389
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	14,377	24,389
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	26,500	23,930
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	26,500	23,930
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	41,054	45,162
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	41,054	45,162
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	17,049	20,623
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	$ 17,049	$ 20,623

Employee and Retiree Benefit_13

Employee and Retiree Benefit Plans - Schedule of 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, 2024	Dec. 31, 2023
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	$ 477,809
Ending balance	492,120	$ 477,809
Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	24,454
Ending balance	18,014	24,454
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	24,454	32,734
Relating to assets held at the reporting date	(3,574)	711
Purchases, sales and settlements	(2,865)	(8,991)
Ending balance	$ 18,015	$ 24,454

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Narrative (Details)	Dec. 31, 2024 derivative	Dec. 31, 2023 derivative derivative_instrument
Derivative [Line Items]
Number of foreign currency derivatives held | derivative	0	0
Commodity Swaps
Derivative [Line Items]
Number of derivative instruments held (in derivatives) | derivative_instrument		0

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Schedule of Crude Oil Derivative Contracts (Details) - Commodity swaps	2 Months Ended	12 Months Ended
	Feb. 27, 2025 MMcf / d $ / Mcf	Dec. 31, 2024 cubicFeetPerDay $ / Mcf
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production (in barrels per day) | cubicFeetPerDay		20,000,000
Average forward price (in USD per barrel)		3.20
February 1,2025 | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production (in barrels per day) | MMcf / d	40
Average forward price (in USD per barrel)	3.58
July 1, 2025 | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production (in barrels per day) | MMcf / d	60
Average forward price (in USD per barrel)	3.65
October 1, 2025 | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production (in barrels per day) | MMcf / d	60
Average forward price (in USD per barrel)	3.74

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Schedule of Fair Value of Derivative Instruments Not Designated as Hedging Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Not Designated as Hedging Instrument | Commodity swaps | Accounts payable
Derivatives, Fair Value [Line Items]
Liability	$ (1,707)	$ 0

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Schedule of 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, 2024	Dec. 31, 2023	Dec. 31, 2022
Commodity swaps
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative instruments	$ (1,707)	$ 0	$ (160,690)
Commodity collars
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative instruments	$ 0	$ 0	$ (159,721)

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Share - Schedule of Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Basic method (in shares)	150,011,458	155,233,560	155,276,533
Dilutive stock options (in shares)	1,015,894	1,412,869	2,198,305
Diluted method (in shares)	151,027,352	156,646,429	157,474,838

Net Income (Loss) Per Common _4

Net Income (Loss) Per Common Share - Schedule of Anti Dilutive Securities Not Included in Computation of Diluted EPS (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	0	0	126,000
Weighted average price of these options (in USD per share)	$ 0	$ 0	$ 49.65

Other Financial Information - N

Other Financial Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Other Financial Information [Abstract]
Net gains (loss) from foreign currency transactions	$ 45.4	$ (10.8)	$ 23

Other Financial Information - S

Other Financial Information - Schedule of Noncash Operating Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$ 71,081	$ 47,151	$ (137,228)
(Increase) decrease in inventories	1,327	329	(1,534)
(Increase) decrease in prepaid expenses	1,192	(1,293)	(3,413)
Increase (decrease) in accounts payable and accrued liabilities	3,287	(140,011)	69,854
Increase (decrease) in income taxes payable	(2,004)	(5,537)	6,593
Net decrease (increase) in non-cash operating working capital	74,883	(99,361)	(65,728)
Supplementary disclosures:
Cash income taxes paid, net of refunds	12,648	12,356	24,853
Interest paid, net of amounts capitalized	78,806	108,912	149,597
Capitalized interest paid	11,400	14,500	16,300
Non-cash investing activities:
Asset retirement costs capitalized	47,233	32,975	(21,147)
(Increase) decrease in capital expenditure accrual	$ (5,935)	$ 17,517	$ (31,397)

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	$ 5,549,653	$ 5,148,893
Before reclassifications to income	(110,979)	9,018
Reclassifications to income	4,024	4,551
Other comprehensive income (loss)	(106,955)	13,569	$ (6,975)
Balance at end of year	5,341,843	5,549,653	5,148,893
Total
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(521,117)	(534,686)	(527,711)
Other comprehensive income (loss)	(106,955)	13,569
Balance at end of year	(628,072)	(521,117)	(534,686)
Foreign Currency Translation Gains (Losses)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(381,632)	(418,230)
Before reclassifications to income	(134,692)	36,598
Reclassifications to income	0	0
Other comprehensive income (loss)	(134,692)	36,598
Balance at end of year	(516,324)	(381,632)	(418,230)
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	(139,485)	(116,456)
Before reclassifications to income	23,713	(27,580)
Reclassifications to income	4,024	4,551
Other comprehensive income (loss)	27,737	(23,029)
Balance at end of year	(111,748)	(139,485)	$ (116,456)
Reclassification before tax	5,400	5,600
Deferred Loss on Interest Rate Derivative Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Reclassification tax	$ 1,400	$ 1,100

Assets and Liabilities Measur_3

Assets and Liabilities Measured at Fair Value - Schedule of Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	$ 21,176	$ 17,785
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	19,469	17,785
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	1,707	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	19,469	17,785
Nonqualified employee savings plan | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	19,469	17,785
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
Commodity swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	1,707	0
Commodity swaps | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Commodity swaps | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	1,707	0
Commodity swaps | 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)	3 Months Ended		12 Months Ended
	Dec. 31, 2024 USD ($) OffsettingPosition	Mar. 31, 2024 USD ($)	Dec. 31, 2024 USD ($) OffsettingPosition	Dec. 31, 2023 USD ($) OffsettingPosition	Dec. 31, 2022 USD ($)
Number of offsetting positions (in offsetting positions) | OffsettingPosition	0		0	0
Impairment of assets	$ 28,400,000	$ 34,500,000	$ 62,909,000	$ 0	$ 0
PAI and LLOG
Derivative liabilities					$ 192,700,000
Commodity swaps | Accounts payable | Not Designated as Hedging Instrument
Liability	$ (1,707,000)		$ (1,707,000)	$ 0

Assets and Liabilities Measur_5

Assets and Liabilities Measured at Fair Value - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Carrying Amount
Current and long-term debt, carrying amount	$ 1,275,374	$ 1,329,075
Fair Value
Current and long-term debt, fair value	$ 1,185,961	$ 1,265,185

Assets and Liabilities Measur_6

Assets and Liabilities Measured at Fair Value - Schedule of Nonrecurring Fair Value Measurements (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2024	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Pretax Impairment	$ 28,400,000	$ 34,500,000	$ 62,909,000	$ 0	$ 0
United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	63,410,000		63,410,000
Total Pretax Impairment			62,909,000	$ 0	$ 0
Level 1 | United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	0		0
Level 2 | United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	0		0
Level 3 | United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	$ 501,000		$ 501,000

Commitments (Details)

Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	$ 290,474
Future rental payments, due year two	123,487
Future rental payments, due year three	66,521
Future rental payments, due year four	59,398
Future rental payments, due year five	56,849
Commitments for capital expenditures	417,000
Gulf of America
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	53,600
Eagle Ford Shale
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	112,200
Canada
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	31,200
Vietnam
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	220,000
Commitments for operating agreements	178,000
Processing production handling and transportation services
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	148,800
Future rental payments, due year two	117,700
Future rental payments, due year three	105,500
Future rental payments, due year four	96,000
Future rental payments, due year five	64,200
Processing and transportation charges	$ 225,900	$ 295,100	$ 216,400

Environmental and Other Conti_2

Environmental and Other Contingencies (Details) $ in Millions	Dec. 31, 2024 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 - Schedule of Number of Shares of Common Stock Issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning of year (in shares)	152,748,642	155,467,319	154,463,050
Stock options exercised (in shares)	0	2,657	181,655
Restricted stock awards (in shares)	1,105,268	689,824	822,614
Treasury shares purchased (in shares)	(8,008,786)	(3,411,158)	0
End of year (in shares)	145,845,124	152,748,642	155,467,319

Common Stock Issued and Outst_4

Common Stock Issued and Outstanding - Narrative (Details) - USD ($)	2 Months Ended	12 Months Ended
	Feb. 25, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program, authorized amount		$ 1,100,000,000
Treasury shares purchased (in shares)		8,008,786	3,411,158	0
Repurchase of common stock		$ 300,000,000
Treasury stock, value, acquired, cost method, net		302,700,000
Stock repurchase program, remaining amount		$ 650,100,000
Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Treasury shares purchased (in shares)	3,400,000
Repurchase of common stock	$ 95,100,000
Stock repurchase program, remaining amount	$ 555,000,000

Business Segments - Schedule of

Business Segments - Schedule of Revenue by Major Customers (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Chevron Corporation
Segment Reporting Information [Line Items]
Concentration risk	13%	16%	19%
ExxonMobil Corporation
Segment Reporting Information [Line Items]
Concentration risk	20%	27%	12%
Phillips 66
Segment Reporting Information [Line Items]
Concentration risk	10%

Business Segments - Narrative (

Business Segments - Narrative (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting [Abstract]
Assets held-for-sale	$ 0	$ 0

Business Segments - Schedule _2

Business Segments - Schedule of Segment Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 669,600,000	$ 753,200,000	$ 801,000,000	$ 794,800,000	$ 842,200,000	$ 953,800,000	$ 812,900,000	$ 840,000,000	$ 3,018,598,000	$ 3,448,854,000	$ 4,220,140,000
Gain on sales of assets and other operating income									9,900,000	11,300,000	(287,500,000)
Total revenues and other income									3,028,474,000	3,460,147,000	3,932,662,000
Lease operating expenses and taxes other than income									649,700,000	678,900,000	607,600,000
Repair and maintenance									68,500,000	58,200,000	39,600,000
Workovers									218,800,000	47,300,000	32,100,000
Total lease operating expenses									936,960,000	784,391,000	679,342,000
Severance and ad valorem taxes									39,162,000	42,787,000	57,012,000
Transportation, gathering and processing									210,827,000	232,985,000	212,711,000
Costs of purchased natural gas									3,147,000	51,682,000	171,991,000
Selling and general expenses									112,900,000	118,900,000	133,300,000
Geological and geophysical									27,200,000	26,100,000	10,500,000
Dry holes and previously suspended exploration costs									73,200,000	169,800,000	82,100,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									33,100,000	38,900,000	40,600,000
Exploration Expenses									133,538,000	234,776,000	133,197,000
Depreciation, depletion and amortization									865,800,000	861,500,000	776,800,000
Impairment of assets	28,400,000			34,500,000					62,909,000	0	0
Accretion of asset retirement obligations									52,511,000	46,059,000	46,243,000
Other operating expenses									11,000,000	39,300,000	59,200,000
Loss on contingent consideration									0	7,113,000	78,285,000
Total other operating expenses										(46,400,000)	(137,500,000)
Interest Income									(34,200,000)	(12,600,000)	(2,800,000)
Interest expense, net of capitalization									105,926,000	112,373,000	150,759,000
Current income tax expense									5,800,000	16,200,000	23,400,000
Deferred income tax expense									72,500,000	179,800,000	286,100,000
Total income tax expense									78,300,000	196,000,000	309,500,000
Other segment items									(36,700,000)	21,000,000	(11,500,000)
Net income including noncontrolling interest	64,400,000	$ 151,100,000	$ 156,300,000	$ 114,700,000	139,700,000	$ 277,800,000	$ 91,900,000	$ 214,300,000	486,485,000	723,681,000	1,138,719,000
Additions to property, plant, equipment									840,600,000	914,800,000	1,063,300,000
Total assets at year-end	9,667,479,000				9,766,697,000				9,667,479,000	9,766,697,000	10,309,000,000
Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,014,856,000	3,376,639,000	4,038,451,000
Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,742,000	72,215,000	181,689,000
Operating Segments
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									6,000,000	8,000,000	26,900,000
Total revenues and other income									3,024,600,000	3,456,800,000	4,247,100,000
Lease operating expenses and taxes other than income									649,700,000	678,900,000	607,600,000
Repair and maintenance									68,500,000	58,200,000	39,600,000
Workovers									218,800,000	47,300,000	32,100,000
Total lease operating expenses									937,000,000	784,400,000	679,300,000
Severance and ad valorem taxes									39,200,000	42,800,000	57,000,000
Transportation, gathering and processing									210,800,000	233,000,000	212,700,000
Costs of purchased natural gas									3,100,000	51,700,000	172,000,000
Selling and general expenses									23,800,000	37,700,000	44,500,000
Geological and geophysical									27,200,000	26,100,000	10,500,000
Dry holes and previously suspended exploration costs									73,200,000	169,800,000	82,100,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									33,100,000	38,900,000	40,600,000
Exploration Expenses									133,500,000	234,800,000	133,200,000
Depreciation, depletion and amortization									856,900,000	850,500,000	763,900,000
Impairment of assets									62,900,000
Accretion of asset retirement obligations									52,400,000	46,000,000	46,200,000
Other operating expenses									14,200,000	43,700,000	54,200,000
Loss on contingent consideration										7,100,000	78,300,000
Total other operating expenses										(50,800,000)	(132,500,000)
Interest Income									(22,000,000)	(3,300,000)	(300,000)
Interest expense, net of capitalization									800,000	500,000	400,000
Current income tax expense									4,900,000	7,400,000	19,200,000
Deferred income tax expense									101,400,000	230,400,000	398,100,000
Total income tax expense									106,300,000	237,800,000	417,300,000
Other segment items									7,300,000	8,900,000	9,300,000
Net income including noncontrolling interest									598,400,000	881,200,000	1,579,100,000
Additions to property, plant, equipment									811,400,000	890,600,000	1,041,400,000
Total assets at year-end	9,175,600,000				9,400,200,000				9,175,600,000	9,400,200,000	9,273,600,000
Operating Segments | United States
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									4,500,000	6,500,000	25,500,000
Total revenues and other income									2,508,300,000	2,928,300,000	3,461,200,000
Lease operating expenses and taxes other than income									471,300,000	532,300,000	458,200,000
Repair and maintenance									63,700,000	53,200,000	34,900,000
Workovers									214,900,000	45,200,000	29,600,000
Total lease operating expenses									749,900,000	630,700,000	522,700,000
Severance and ad valorem taxes									37,800,000	41,400,000	55,700,000
Transportation, gathering and processing									130,900,000	157,000,000	142,200,000
Costs of purchased natural gas									0	0	200,000
Selling and general expenses									(3,300,000)	11,800,000	20,400,000
Geological and geophysical									14,400,000	6,600,000	8,300,000
Dry holes and previously suspended exploration costs									70,900,000	153,100,000	23,000,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									10,900,000	14,900,000	16,200,000
Exploration Expenses									96,200,000	174,600,000	47,500,000
Depreciation, depletion and amortization									709,200,000	706,000,000	617,000,000
Impairment of assets									62,900,000
Accretion of asset retirement obligations									43,100,000	37,800,000	36,500,000
Other operating expenses									9,300,000	20,100,000	41,300,000
Loss on contingent consideration										7,100,000	78,300,000
Total other operating expenses										(27,200,000)	(119,600,000)
Interest Income									(22,000,000)	(3,300,000)	(300,000)
Interest expense, net of capitalization									200,000	100,000	100,000
Current income tax expense									1,500,000	3,100,000	8,100,000
Deferred income tax expense									123,800,000	229,600,000	362,700,000
Total income tax expense									125,300,000	232,700,000	370,800,000
Other segment items									6,900,000	7,200,000	6,900,000
Net income including noncontrolling interest									561,900,000	905,100,000	1,521,900,000
Additions to property, plant, equipment									601,700,000	671,300,000	838,600,000
Total assets at year-end	6,953,800,000				7,107,000,000				6,953,800,000	7,107,000,000	6,930,600,000
Operating Segments | Canada
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									1,500,000	1,500,000	1,400,000
Total revenues and other income									509,700,000	517,500,000	762,900,000
Lease operating expenses and taxes other than income									176,800,000	144,700,000	147,900,000
Repair and maintenance									4,800,000	5,000,000	4,700,000
Workovers									3,900,000	2,100,000	2,500,000
Total lease operating expenses									185,500,000	151,800,000	155,100,000
Severance and ad valorem taxes									1,400,000	1,400,000	1,300,000
Transportation, gathering and processing									79,900,000	76,000,000	70,500,000
Costs of purchased natural gas									3,100,000	51,700,000	171,800,000
Selling and general expenses									20,400,000	16,500,000	21,900,000
Geological and geophysical									200,000	100,000	400,000
Dry holes and previously suspended exploration costs									0	0	0
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									300,000	400,000	700,000
Exploration Expenses									500,000	500,000	1,100,000
Depreciation, depletion and amortization									146,000,000	142,200,000	141,500,000
Impairment of assets									0
Accretion of asset retirement obligations									8,600,000	7,800,000	9,600,000
Other operating expenses									2,800,000	15,500,000	10,500,000
Loss on contingent consideration										0	0
Total other operating expenses										(15,500,000)	(10,500,000)
Interest Income									0	0	0
Interest expense, net of capitalization									400,000	200,000	0
Current income tax expense									3,200,000	3,700,000	8,800,000
Deferred income tax expense									8,800,000	7,500,000	34,800,000
Total income tax expense									12,000,000	11,200,000	43,600,000
Other segment items									100,000	1,100,000	1,800,000
Net income including noncontrolling interest									49,000,000	41,600,000	134,200,000
Additions to property, plant, equipment									137,900,000	206,200,000	208,500,000
Total assets at year-end	1,919,800,000				2,080,000,000				1,919,800,000	2,080,000,000	2,125,600,000
Operating Segments | Other
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									0	0	0
Total revenues and other income									6,600,000	11,000,000	23,000,000
Lease operating expenses and taxes other than income									1,600,000	1,900,000	1,500,000
Repair and maintenance									0	0	0
Workovers									0	0	0
Total lease operating expenses									1,600,000	1,900,000	1,500,000
Severance and ad valorem taxes									0	0	0
Transportation, gathering and processing									0	0	0
Costs of purchased natural gas									0	0	0
Selling and general expenses									6,700,000	9,400,000	2,200,000
Geological and geophysical									12,600,000	19,400,000	1,800,000
Dry holes and previously suspended exploration costs									2,300,000	16,700,000	59,100,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									21,900,000	23,600,000	23,700,000
Exploration Expenses									36,800,000	59,700,000	84,600,000
Depreciation, depletion and amortization									1,700,000	2,300,000	5,400,000
Impairment of assets									0
Accretion of asset retirement obligations									700,000	400,000	100,000
Other operating expenses									2,100,000	8,100,000	2,400,000
Loss on contingent consideration										0	0
Total other operating expenses										(8,100,000)	(2,400,000)
Interest Income									0	0	0
Interest expense, net of capitalization									200,000	200,000	300,000
Current income tax expense									200,000	600,000	2,300,000
Deferred income tax expense									(31,200,000)	(6,700,000)	600,000
Total income tax expense									(31,000,000)	(6,100,000)	2,900,000
Other segment items									300,000	600,000	600,000
Net income including noncontrolling interest									(12,500,000)	(65,500,000)	(77,000,000)
Additions to property, plant, equipment									71,800,000	13,100,000	(5,700,000)
Total assets at year-end	302,000,000				213,300,000				302,000,000	213,300,000	217,400,000
Operating Segments | Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,014,900,000	3,376,600,000	4,038,500,000
Operating Segments | Revenue from production | United States
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,503,800,000	2,921,800,000	3,435,500,000
Operating Segments | Revenue from production | Canada
Segment Reporting Information [Line Items]
Revenue from contracts with customers									504,500,000	443,800,000	580,000,000
Operating Segments | Revenue from production | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									6,600,000	11,000,000	23,000,000
Operating Segments | Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,700,000	72,200,000	181,700,000
Operating Segments | Sales of purchased natural gas | United States
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	200,000
Operating Segments | Sales of purchased natural gas | Canada
Segment Reporting Information [Line Items]
Revenue from contracts with customers									3,700,000	72,200,000	181,500,000
Operating Segments | Sales of purchased natural gas | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Corporate and Other
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									3,900,000	3,300,000	(314,400,000)
Total revenues and other income									3,900,000	3,300,000	(314,400,000)
Lease operating expenses and taxes other than income									0	0	0
Repair and maintenance									0	0	0
Workovers									0	0	0
Total lease operating expenses									0	0	0
Severance and ad valorem taxes									0	0	0
Transportation, gathering and processing									0	0	0
Costs of purchased natural gas									0	0	0
Selling and general expenses									89,100,000	81,200,000	88,800,000
Geological and geophysical									0	0	0
Dry holes and previously suspended exploration costs									0	0	0
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									0	0	0
Exploration Expenses									0	0	0
Depreciation, depletion and amortization									8,900,000	11,000,000	12,900,000
Impairment of assets									0
Accretion of asset retirement obligations									100,000	100,000	0
Other operating expenses									(3,200,000)	(4,400,000)	5,000,000
Loss on contingent consideration										0	0
Total other operating expenses										4,400,000	(5,000,000)
Interest Income									(12,200,000)	(9,300,000)	(2,500,000)
Interest expense, net of capitalization									105,100,000	111,900,000	150,400,000
Current income tax expense									900,000	8,800,000	4,200,000
Deferred income tax expense									(28,900,000)	(50,600,000)	(112,000,000)
Total income tax expense									(28,000,000)	(41,800,000)	(107,800,000)
Other segment items									(44,000,000)	12,100,000	(20,800,000)
Net income including noncontrolling interest									(111,900,000)	(157,500,000)	(440,400,000)
Additions to property, plant, equipment									29,200,000	24,200,000	21,900,000
Total assets at year-end	$ 491,900,000				$ 366,500,000				491,900,000	366,500,000	1,035,400,000
Corporate and Other | Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Corporate and Other | Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ 0	$ 0	$ 0

Business Segments - Schedule _3

Business Segments - Schedule of Geographic Information on Certain Long-Lived Assets (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 8,054.6	$ 8,225.1	$ 8,228
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	6,415.9	6,555	6,562.8
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	1,389.5	1,497.3	1,499.1
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 249.2	$ 172.8	$ 166.1

Leases - Narrative (Details)

Leases - Narrative (Details)	12 Months Ended
	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Termination period	1 month
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	16 years

Leases - Schedule of Lease Rela

Leases - Schedule of Lease Related Expenses (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Amortization of asset	$ 855,000	$ 1,505,000
Interest on lease liabilities	193,000	221,000
Sublease income	(1,143,000)	(1,402,000)
Net lease expense	761,091,000	667,990,000
Variable lease expenses primarily related to additional volumes processed at natural gas processing plant	42,300,000	36,700,000
Lease operating expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	411,303,000	246,721,000
Short-term lease cost	236,400,000	78,200,000
Transportation, gathering and processing
Lessee, Lease, Description [Line Items]
Operating lease cost	16,117,000	37,797,000
Short-term lease cost	13,000,000	29,400,000
Selling and general expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	10,990,000	9,859,000
Short-term lease cost	800,000	1,600,000
Other operating expense
Lessee, Lease, Description [Line Items]
Operating lease cost	6,622,000	675,000
Short-term lease cost	6,200,000	300,000
Exploration expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	38,974,000	110,577,000
Short-term lease cost	38,500,000	80,300,000
Property, plant and equipment
Lessee, Lease, Description [Line Items]
Operating lease cost	277,170,000	204,595,000
Short-term lease cost	97,100,000	112,700,000
Asset retirement obligations
Lessee, Lease, Description [Line Items]
Operating lease cost	10,000	57,442,000
Short-term lease cost	$ 0	$ 57,400,000

Leases - Schedule of Maturity o

Leases - Schedule of Maturity of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Operating Leases
2025	$ 290,474
2026	123,487
2027	66,521
2028	59,398
2029	56,849
Remaining	406,450
Total future minimum lease payments	1,003,179
Less imputed interest	(212,590)
Lease obligation	790,589
Finance Leases
2025	1,257
2026	1,257
2027	1,257
2028	1,257
2029	456
Remaining	927
Total future minimum lease payments	6,411
Less imputed interest	(1,534)
Present value of lease liabilities	$ 4,877	$ 4,238
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
2025	$ 291,731
2026	124,744
2027	67,778
2028	60,655
2029	57,305
Remaining	407,377
Total future minimum lease payments	1,009,590
Less imputed interest	(214,124)
Present value of lease liabilities	$ 795,466

Leases - Schedule of Lease Term

Leases - Schedule of Lease Term and Discount Rate (Details)	Dec. 31, 2024	Dec. 31, 2023
Weighted average remaining lease term:
Operating leases	8 years	10 years
Finance leases	6 years	5 years
Weighted average discount rate:
Operating leases	5.70%	5.90%
Finance leases	4.90%	4.70%

Leases - Schedule of Other Leas

Leases - Schedule of Other Lease Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 328,847	$ 271,488
Operating cash flows from finance leases	311	221
Financing cash flows from finance leases	665	622	$ 636
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	349,312	5,923
Offshore drilling rig
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	254,100	$ 4,500
Offshore Two Drilling Rig
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$ 52,700

Subsequent Event (Details)

Subsequent Event (Details) - Subsequent Event	Jan. 30, 2025 $ / shares
O 2025 A Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)	$ 1.30
O 2025 Q1 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)	0.325
O 2025 Q2 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)	0.325
O 2025 Q3 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)	0.325
O 2025 Q4 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)	$ 0.325

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information (Unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 $ / bbl ft³	Dec. 31, 2023 $ / bbl	Dec. 31, 2022 $ / bbl
Oil and Gas, Proved Reserve, Quantity [Line Items]
Future net cash flows annual discount factor, percentage	10%
Equity Method Investee
Oil and Gas, Proved Reserve, Quantity [Line Items]
Reserves attributable to investees accounted for my the equity method | ft³	0
Net crude oil and condensate revenue
Oil and Gas, Proved Reserve, Quantity [Line Items]
Average production costs per barrel of oil (in dollars per barrel)	75.48	78.22	93.67
Net natural gas revenue
Oil and Gas, Proved Reserve, Quantity [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot)	2.13	2.64	6.36

Supplemental Oil and Gas Info_4

Supplemental Oil and Gas Information (Unaudited) - Schedule of Proved Reserves Based on Average Prices (Details) MMcf in Millions, MMBbls in Millions, ft³ in Billions	12 Months Ended
	Dec. 31, 2024 MMBbls ft³	Dec. 31, 2024 ft³ MMBbls	Dec. 31, 2024 MMBbls MMcf ft³	Dec. 31, 2023 ft³ MMBbls MMcf	Dec. 31, 2022 MMBbls ft³ MMcf	Dec. 31, 2021 ft³ MMBbls
Proved developed and undeveloped oil reserves:
Proved developed reserves	436.2	436.2	436.2	425.5	436	419.2
Proved undeveloped reserves	292.8	292.8	292.8	314	279.4	297.7
Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	739.5			715.4	716.9
Revisions of previous estimates	14.3			(13.3)	(23.6)
Improved recovery	11.3			0.4	5.3
Extensions and discoveries	31.4			112.6	80.1
Purchases of properties					5
Sale of properties				(5.2)	(4.4)
Production	(67.5)			(70.4)	(63.9)
Proved developed and undeveloped reserves, ending balance	729			739.5	715.4
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	275.8			303.6	291.5
Revisions of previous estimates	6.6			(10.8)	23.4
Improved recovery	10.7			0.4	4.7
Extensions and discoveries	16.6			22.5	18.9
Purchases of properties					4.2
Sale of properties				(2)	(3.6)
Production	(34.6)			(37.9)	(35.5)
Proved developed and undeveloped reserves, ending balance	275.1			275.8	303.6
Proved developed reserves	184.7	184.7	184.7	186.3	209	191.5
Proved undeveloped reserves	90.4	90.4	90.4	89.5	94.6	99.9
Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	37.6			41.7	38.4
Revisions of previous estimates	1.2			(1.4)	4.4
Improved recovery			0.4		0.2
Extensions and discoveries	2.9			2	2.5
Purchases of properties					0.3
Sale of properties				(0.6)	(0.2)
Production	(3.5)			(4.1)	(3.9)
Proved developed and undeveloped reserves, ending balance	38.6			37.6	41.7
Proved developed reserves	24.1	24.1	24.1	25.9	29.7	28.4
Proved undeveloped reserves	14.5	14.5	14.5	11.7	12	10
Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance | ft³		2,556.2		2,219.9	2,322.3
Revisions of previous estimates | ft³		39.1		(6.9)	(309.8)
Improved recovery			1,200		2,600
Extensions and discoveries | ft³		71.4		528.9	352.4
Purchases of properties | ft³					2.9
Sale of properties				(15,600)	(3.6)
Production | ft³		(176.1)		(170.1)	(146.9)
Proved developed and undeveloped reserves, ending balance | ft³		2,491.8		2,556.2	2,219.9
Proved developed reserves | ft³	1,364.2	1,364.2	1,364.2	1,279.3	1,183.1	1,196
Proved undeveloped reserves | ft³	1,127.6	1,127.6	1,127.6	1,276.9	1,036.8	1,126.4
MP Gulf of Mexico LLC
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	15.9
Proved developed reserves	14.4	14.4	14.4
Proved undeveloped reserves	1.5	1.5	1.5
MP Gulf of Mexico LLC | Net crude oil and condensate revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	14.5
Proved developed reserves	13.2	13.2	13.2
Proved undeveloped reserves	1.3	1.3	1.3
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	1.1
Proved developed reserves	0.5	0.5	0.5
Proved undeveloped reserves	0.1	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
Proved developed reserves | ft³	4.2	4.2	4.2
Proved undeveloped reserves | ft³	0.8	0.8	0.8
United States - Offshore
Proved developed and undeveloped oil reserves:
Proved developed reserves	218.9	218.9	218.9	223.2	264.2	241.9
Proved undeveloped reserves	88.5	88.5	88.5	87.9	92.8	101.6
United States - Offshore | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	311.1			357	343.4
Revisions of previous estimates	8.1			(13.3)	29
Improved recovery	11.3			0	5.3
Extensions and discoveries	16			12.7	20.6
Purchases of properties					5
Sale of properties				0	(4.4)
Production	(39.1)			(45.3)	(41.9)
Proved developed and undeveloped reserves, ending balance	307.4			311.1	357
United States - Offshore | 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	228			263.6	255
Revisions of previous estimates	6.6			(8.9)	19.9
Improved recovery	10.7			0	4.7
Extensions and discoveries	10.7			8.9	16.1
Purchases of properties					4.2
Sale of properties				0	(3.6)
Production	(30.8)			(35.6)	(32.7)
Proved developed and undeveloped reserves, ending balance	225.2			228	263.6
Proved developed reserves	164.1	164.1	164.1	163.7	194.4	174.9
Proved undeveloped reserves	61.1	61.1	61.1	64.3	69.2	80
United States - Offshore | Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	34.3			37.6	35.1
Revisions of previous estimates	0.3			(1.2)	3.9
Improved recovery			0.4		0.2
Extensions and discoveries	2.4			1.7	1.9
Purchases of properties					0.3
Sale of properties				0	(0.2)
Production	(3.3)			(3.8)	(3.6)
Proved developed and undeveloped reserves, ending balance	34.1	67.9		34.3	37.6
Proved developed reserves	21.9	21.9	21.9	24.1	27.4	25.6
Proved undeveloped reserves	12.2	12.2	12.2	10.2	10.2	9.5
United States - Offshore | Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance | ft³		293.1		334.9	320.3
Revisions of previous estimates | ft³		7.7		(19)	30.7
Improved recovery			1,200		2,600
Extensions and discoveries | ft³		17		12.3	15.7
Purchases of properties | ft³					2.9
Sale of properties				0	(3.6)
Production | ft³		(30.1)		(35.1)	(33.7)
Proved developed and undeveloped reserves, ending balance | ft³		288.9		293.1	334.9
Proved developed reserves | ft³	196.8	196.8	196.8	212.4	254.1	248.1
Proved undeveloped reserves | ft³	92.1	92.1	92.1	80.7	80.8	72.2
Canada
Proved developed and undeveloped oil reserves:
Proved developed reserves	217.1	217.1	217.1	202	171.3	176.8
Proved undeveloped reserves	191.8	191.8	191.8	213.5	186.5	196
Canada | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	415.5			357.8	372.8
Revisions of previous estimates	6.3			0.2	(52.8)
Improved recovery	0			0.4	0
Extensions and discoveries	15.4			87.3	59.5
Purchases of properties					0
Sale of properties				(5.2)	0
Production	(28.3)			(25)	(21.7)
Proved developed and undeveloped reserves, ending balance	408.9			415.5	357.8
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	35.4			39.5	35.9
Revisions of previous estimates	0.1			(1.8)	3.3
Improved recovery	0			0.4	0
Extensions and discoveries	5.9			1.5	2.8
Purchases of properties					0
Sale of properties				(2)	0
Production	(3.7)			(2.2)	(2.5)
Proved developed and undeveloped reserves, ending balance	37.7			35.4	39.5
Proved developed reserves	20.4	20.4	20.4	22.3	14.2	16
Proved undeveloped reserves	17.3	17.3	17.3	13.1	25.3	19.8
Canada | Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	3.3			4.1	3.3
Revisions of previous estimates	0.9			(0.2)	0.5
Improved recovery			0		0
Extensions and discoveries	0.5			0.3	0.6
Purchases of properties					0
Sale of properties				(0.6)	0
Production	(0.2)			(0.3)	(0.3)
Proved developed and undeveloped reserves, ending balance	4.5	36		3.3	4.1
Proved developed reserves	2.2	2.2	2.2	1.8	2.3	2.8
Proved undeveloped reserves	2.3	2.3	2.3	1.5	1.8	0.5
Canada | Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance | ft³		2,260.1		1,884.8	2,001.8
Revisions of previous estimates | ft³		31.4		12.1	(340.5)
Improved recovery			0		0
Extensions and discoveries | ft³		54.4		513.8	336.7
Purchases of properties | ft³					0
Sale of properties				(15,600)	0
Production | ft³		(146)		(135)	(113.2)
Proved developed and undeveloped reserves, ending balance | ft³		2,199.9		2,260.1	1,884.8
Proved developed reserves | ft³	1,167.2	1,167.2	1,167.2	1,066.7	928.8	947.7
Proved undeveloped reserves | ft³	1,032.7	1,032.7	1,032.7	1,193.4	956	1,054.1
Other
Proved developed and undeveloped oil reserves:
Proved developed reserves	0.2	0.2	0.2	0.3	0.5	0.6
Proved undeveloped reserves	12.5	12.5	12.5	12.6	0.1	0.1
Other | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance	12.9			0.6	0.7
Revisions of previous estimates	(0.1)			(0.2)	0.2
Improved recovery	0			0
Extensions and discoveries	0			12.6	0
Purchases of properties					0
Sale of properties				0	0
Production	(0.1)			(0.1)	(0.3)
Proved developed and undeveloped reserves, ending balance	12.7			12.9	0.6
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	12.4			0.5	0.6
Revisions of previous estimates	(0.1)			(0.1)	0.2
Improved recovery	0			0
Extensions and discoveries	0			12.1	0
Purchases of properties					0
Sale of properties				0	0
Production	(0.1)			(0.1)	(0.3)
Proved developed and undeveloped reserves, ending balance	12.2			12.4	0.5
Proved developed reserves	0.2	0.2	0.2	0.3	0.4	0.5
Proved undeveloped reserves	12	12	12	12.1	0.1	0.1
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		0
Extensions and discoveries	0			0	0
Purchases of properties					0
Sale 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	0
Proved undeveloped reserves	0	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		3		0.2	0.2
Revisions of previous estimates | ft³		0		0	0
Improved recovery			0		0
Extensions and discoveries | ft³		0		2.8	0
Purchases of properties | ft³					0
Sale of properties				0	0
Production | ft³		0		0	0
Proved developed and undeveloped reserves, ending balance | ft³		3		3	0.2
Proved developed reserves | ft³	0.2	0.2	0.2	0.2	0.2	0.2
Proved undeveloped reserves | ft³	2.8	2.8	2.8	2.8	0	0
Malaysia | Crude Oil
Proved developed and undeveloped oil reserves:
Improved recovery					0
Malaysia | Net crude oil and condensate revenue | Crude Oil
Proved developed and undeveloped oil reserves:
Improved recovery					0

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information (Unaudited) - Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Property acquisition costs
Unproved	$ 8	$ 8.5	$ 1.8
Proved	0	27.1	128.5
Total acquisition costs	8	35.6	130.3
Exploration costs	145.9	198.1	113.3
Development costs	781.5	880.8	917.7
Total costs incurred	935.4	1,114.5	1,161.3
Charged to expense
Dry hole expense	73.2	169.8	82.1
Geophysical and other costs	50.8	54.1	37.7
Total charged to expense	124	223.9	119.8
Property additions	811.4	890.6	1,041.5
United States - Offshore
Property acquisition costs
Unproved	7.8	0	1.8
Proved	0	12.8	128.5
Total acquisition costs	7.8	12.8	130.3
Exploration costs	85.3	157.8	42.2
Development costs	598.7	667.2	704.9
Total costs incurred	691.8	837.8	877.4
Charged to expense
Dry hole expense	70.9	153.1	23
Geophysical and other costs	19.2	13.4	15.8
Total charged to expense	90.1	166.5	38.8
Property additions	601.7	671.3	838.6
Canada
Property acquisition costs
Unproved	0.2	0	0
Proved	0	0	0
Total acquisition costs	0.2	0	0
Exploration costs	0.4	0.4	0.8
Development costs	137.7	206.2	208.5
Total costs incurred	138.3	206.6	209.3
Charged to expense
Dry hole expense	0	0	0
Geophysical and other costs	0.4	0.4	0.8
Total charged to expense	0.4	0.4	0.8
Property additions	137.9	206.2	208.5
Other
Property acquisition costs
Unproved	0	8.5	0
Proved	0	14.3	0
Total acquisition costs	0	22.8	0
Exploration costs	60.2	39.9	70.3
Development costs	45.1	7.4	4.3
Total costs incurred	105.3	70.1	74.6
Charged to expense
Dry hole expense	2.3	16.7	59.1
Geophysical and other costs	31.2	40.3	21.1
Total charged to expense	33.5	57	80.2
Property additions	$ 71.8	$ 13.1	$ (5.6)

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues
Revenues	$ 3,018,600	$ 3,448,900	$ 4,220,200
Other operating revenues	6,000	7,900	26,700
Total revenues	3,024,500	3,456,800	4,246,900
Costs and expenses
Lease operating expenses	937,000	784,400	679,300
Severance and ad valorem taxes	39,200	42,800	57,000
Transportation, gathering and processing	210,827	232,985	212,711
Costs of purchased natural gas	3,147	51,682	171,991
Exploration costs charged to expense	123,900	223,900	119,800
Undeveloped lease amortization	9,600	10,900	13,300
Depreciation, depletion and amortization	856,900	850,500	763,900
Accretion of asset retirement obligations	52,400	46,000	46,200
Impairment of assets	62,900
Selling and general expenses	23,800	37,700	44,500
Other expenses (benefits)	300	56,900	141,800
Total costs and expenses	2,319,900	2,337,800	2,250,500
Results of operations before taxes	704,600	1,119,000	1,996,400
Income tax expense (benefit)	106,300	237,800	417,300
Results of operations	598,400	881,200	1,579,100
Crude Oil and Natural Gas Liquids
Revenues
Revenues	2,714,900	3,005,800	3,500,600
Natural Gas
Revenues
Revenues	300,000	370,900	537,900
Sales of purchased natural gas
Revenues
Revenues	3,700	72,200	181,700
United States - Offshore
Revenues
Revenues	2,503,800	2,921,800	3,435,800
Other operating revenues	4,500	6,500	25,400
Total revenues	2,508,300	2,928,300	3,461,200
Costs and expenses
Lease operating expenses	749,900	630,700	522,700
Severance and ad valorem taxes	37,800	41,400	55,700
Transportation, gathering and processing	130,900	157,000	142,200
Costs of purchased natural gas	0	0	200
Exploration costs charged to expense	90,000	166,500	38,800
Undeveloped lease amortization	6,200	8,100	8,700
Depreciation, depletion and amortization	709,200	706,000	617,000
Accretion of asset retirement obligations	43,100	37,800	36,500
Impairment of assets	62,900
Selling and general expenses	(3,300)
Selling and general expenses		11,800	20,400
Other expenses (benefits)	(5,600)	31,200	126,300
Total costs and expenses	1,821,100	1,790,500	1,568,500
Results of operations before taxes	687,200	1,137,800	1,892,700
Income tax expense (benefit)	125,300	232,700	370,800
Results of operations	561,900	905,100	1,521,900
United States - Offshore | Crude Oil and Natural Gas Liquids
Revenues
Revenues	2,436,000	2,829,100	3,210,300
United States - Offshore | Natural Gas
Revenues
Revenues	67,800	92,700	225,300
United States - Offshore | Sales of purchased natural gas
Revenues
Revenues	0	0	200
Canada | Conventional gas
Revenues
Revenues	508,200	516,100	761,600
Other operating revenues	1,500	1,400	1,300
Total revenues	509,700	517,500	762,900
Costs and expenses
Lease operating expenses	185,500	151,800	155,100
Severance and ad valorem taxes	1,400	1,400	1,300
Transportation, gathering and processing	79,900	76,000	70,500
Costs of purchased natural gas	3,100	51,700	171,800
Exploration costs charged to expense	400	400	800
Undeveloped lease amortization	100	100	200
Depreciation, depletion and amortization	146,000	142,200	141,500
Accretion of asset retirement obligations	8,600	7,800	9,600
Impairment of assets	0
Selling and general expenses	20,400	16,500	21,900
Other expenses (benefits)	3,300	16,800	12,400
Total costs and expenses	448,700	464,700	585,100
Results of operations before taxes	61,000	52,800	177,800
Income tax expense (benefit)	12,000	11,200	43,600
Results of operations	49,000	41,600	134,200
Canada | Crude Oil and Natural Gas Liquids | Conventional gas
Revenues
Revenues	272,300	165,700	267,500
Canada | Natural Gas | Conventional gas
Revenues
Revenues	232,200	278,200	312,600
Canada | Sales of purchased natural gas | Conventional gas
Revenues
Revenues	3,700	72,200	181,500
Other
Revenues
Revenues	6,600	11,000	22,800
Other operating revenues		0	0
Total revenues	6,600	11,000	22,800
Costs and expenses
Lease operating expenses	1,600	1,900
Lease operating expenses			1,500
Severance and ad valorem taxes	0	0	0
Transportation, gathering and processing	0	0	0
Costs of purchased natural gas	0	0	0
Exploration costs charged to expense	33,500	57,000	80,200
Undeveloped lease amortization	3,300	2,700	4,400
Depreciation, depletion and amortization	1,700	2,300	5,400
Accretion of asset retirement obligations	700	400	100
Impairment of assets	0
Selling and general expenses	6,700	9,400	2,200
Other expenses (benefits)	2,600	8,900	3,100
Total costs and expenses	50,100	82,600	96,900
Results of operations before taxes	(43,500)	(71,600)	(74,100)
Income tax expense (benefit)	(31,000)	(6,100)	2,900
Results of operations	(12,500)	(65,500)	(77,000)
Other | Crude Oil and Natural Gas Liquids
Revenues
Revenues	6,600	11,000	22,800
Other | Natural Gas
Revenues
Revenues	0	0	0
Other | Sales of purchased natural gas
Revenues
Revenues	$ 0	$ 0	$ 0

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	$ 25,435.4	$ 27,944.5	$ 39,697.3
Future development costs	(3,103.3)	(2,759.2)	(2,238.3)
Future production costs	(12,013.9)	(12,368.5)	(12,508.5)
Future income taxes	(1,348.1)	(1,813.4)	(4,400.9)
Future net cash flows	8,970.1	11,003.4	20,549.6
10% annual discount for estimated timing of cash flows	(3,574.2)	(4,150)	(8,736.4)
Standardized measure of discounted future net cash flows	5,395.9	6,853.4	11,813.2	$ 7,299
United States - Offshore
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	18,118.1	18,927.6	27,277.9
Future development costs	(2,024.9)	(1,685.3)	(1,594.5)
Future production costs	(7,645.7)	(7,856.2)	(8,297.4)
Future income taxes	(893.5)	(1,057.5)	(2,606.8)
Future net cash flows	7,554	8,328.6	14,779.2
10% annual discount for estimated timing of cash flows	(2,887.3)	(2,840.6)	(5,709.8)
Standardized measure of discounted future net cash flows	4,666.7	5,488	9,069.4
Canada
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	6,304.4	8,012.7	12,360.2
Future development costs	(825.9)	(769.6)	(642.4)
Future production costs	(4,026.5)	(4,223.6)	(4,199)
Future income taxes	(251.2)	(634.6)	(1,788.7)
Future net cash flows	1,200.8	2,384.9	5,730.1
10% annual discount for estimated timing of cash flows	(486)	(1,056.9)	(3,015.6)
Standardized measure of discounted future net cash flows	714.8	1,328	2,714.5
Other
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	1,012.9	1,004.2	59.2
Future development costs	(252.5)	(304.3)	(1.4)
Future production costs	(341.7)	(288.7)	(12.1)
Future income taxes	(203.4)	(121.3)	(5.4)
Future net cash flows	215.3	289.9	40.3
10% annual discount for estimated timing of cash flows	(200.9)	(252.5)	(11)
Standardized measure of discounted future net cash flows	$ 14.4	$ 37.4	$ 29.3

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information (Unaudited) - Schedule of Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) $ / bbl	Dec. 31, 2023 USD ($) $ / bbl	Dec. 31, 2022 USD ($) $ / bbl
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]
Net changes in prices and production costs	$ (1,116.5)	$ (5,845.6)	$ 4,812.2
Net changes in development costs	(152.7)	(78.8)	(531.1)
Sales and transfers of oil and natural gas produced, net of production costs	(1,824.8)	(2,264.8)	(2,917.4)
Net change due to extensions and discoveries	583.7	770.4	1,223.5
Net change due to purchases and sales of proved reserves	0	(96.1)	102.1
Development costs incurred	668.6	703.7	769.3
Accretion of discount	773.5	1,393.3	802.6
Revisions of previous quantity estimates	(688.1)	(771.5)	1,652.9
Net change in income taxes	298.8	1,229.6	(1,399.9)
Net (decrease) increase	(1,457.5)	(4,959.8)	4,514.2
Standardized measure, beginning balance	6,853.4	11,813.2	7,299
Standardized measure, ending balance	$ 5,395.9	$ 6,853.4	$ 11,813.2
Net crude oil and condensate revenue
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]
Average production costs per barrel of oil (in dollars per barrel) | $ / bbl	75.48	78.22	93.67
Net natural gas revenue
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot) | $ / bbl	2.13	2.64	6.36

Supplemental Oil and Gas Info_9

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	$ 283	$ 400.1
Proved oil and natural gas properties	21,343.6	20,738.1
Gross capitalized costs	21,626.6	21,138.2
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(131.7)	(122.7)
Proved oil and natural gas properties	(13,486.6)	(12,829.4)
Net capitalized costs	8,008.3	8,186.1
United States - Offshore
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	247.3	337.3
Proved oil and natural gas properties	16,598.8	15,868.4
Gross capitalized costs	16,846.1	16,205.7
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(111)	(105.3)
Proved oil and natural gas properties	(10,326.2)	(9,552.9)
Net capitalized costs	6,408.9	6,547.5
Canada
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	6.6	13.1
Proved oil and natural gas properties	4,498.1	4,716
Gross capitalized costs	4,504.7	4,729.1
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	0	0
Proved oil and natural gas properties	(3,116.2)	(3,233.7)
Net capitalized costs	1,388.5	1,495.4
Other
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	29.1	49.7
Proved oil and natural gas properties	246.7	153.7
Gross capitalized costs	275.8	203.4
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(20.7)	(17.4)
Proved oil and natural gas properties	(44.2)	(42.8)
Net capitalized costs	$ 210.9	$ 143.2

Supplemental Quarterly Inform_3

Supplemental Quarterly Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Interim Reporting [Line Items]
Revenue from contracts with customers	$ 669,600	$ 753,200	$ 801,000	$ 794,800	$ 842,200	$ 953,800	$ 812,900	$ 840,000	$ 3,018,598	$ 3,448,854	$ 4,220,140
Income from continuing operations before income taxes	78,600	153,800	189,600	145,600	169,500	356,300	127,300	267,900	567,569	921,069	1,450,261
Income from continuing operations	65,200	151,700	156,900	115,500	140,500	278,200	92,500	214,000	489,297	725,148	1,140,797
Net income including noncontrolling interest	64,400	151,100	156,300	114,700	139,700	277,800	91,900	214,300	486,485	723,681	1,138,719
Net income attributable to Murphy	$ 50,300	$ 139,100	$ 127,700	$ 90,000	$ 116,400	$ 255,300	$ 98,300	$ 191,600	$ 407,171	$ 661,559	$ 965,047
Income from continuing operations per common share
Basic (in USD per share)	$ 0.35	$ 0.93	$ 0.84	$ 0.60	$ 0.76	$ 1.64	$ 0.63	$ 1.23	$ 2.73	$ 4.27	$ 6.23
Diluted (in USD per share)	0.34	0.93	0.83	0.60	0.75	1.63	0.62	1.22	2.72	4.23	6.14
Net income per common share
Basic (in USD per share)	0.35	0.93	0.84	0.59	0.76	1.64	0.63	1.23	2.71	4.26	6.22
Diluted (in USD per share)	0.34	0.93	0.83	0.59	0.75	1.63	0.62	1.22	2.70	4.22	6.13
Cash dividend per Common share (in USD per share)	$ 0.300	$ 0.300	$ 0.300	$ 0.300	$ 0.275	$ 0.275	$ 0.275	$ 0.275	$ 1.200	$ 1.100	$ 0.825
Minimum
Interim Reporting [Line Items]
Income from continuing operations before income taxes									$ 567,600	$ 921,000
Maximum
Interim Reporting [Line Items]
Income from continuing operations									489,300	$ 725,200
Net income attributable to Murphy									$ 407,100

Schedule II - Valuation Accou_2

Schedule II - Valuation Accounts and Reserves (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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	146.9	136	111.2
Charged to Expense	2.6	10.9	24.8
Deductions	0	0	0
Other	0	0	0
Ending balance	$ 149.5	$ 146.9	$ 136