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Employee and Retiree Benefit Plans - Schedule of Weighted Average Asset Allocation for Funded Pension Benefit Plans (Details)	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100.00%	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	45.20%	57.30%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	42.70%	36.20%
Alternatives
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	7.40%	3.70%
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	4.70%	2.80%

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (k)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Business Segments - Schedule of Segment Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 613,100,000	$ 721,000,000.0	$ 683,000,000.0	$ 672,700,000	$ 669,600,000	$ 753,200,000	$ 801,000,000.0	$ 794,800,000	$ 2,689,845,000	$ 3,018,598,000	$ 3,448,854,000
Gain on sales of assets and other operating income									31,400,000	9,900,000	11,300,000
Total revenues and other income									2,721,200,000	3,028,500,000	3,460,100,000
Lease operating expenses
Lease operating expenses and taxes other than income									572,800,000	649,700,000	678,900,000
Repair and maintenance									65,900,000	68,500,000	58,200,000
Workovers									126,500,000	218,800,000	47,300,000
Total lease operating expenses									765,240,000	936,960,000	784,391,000
Severance and ad valorem taxes									39,238,000	39,162,000	42,787,000
Transportation, gathering and processing									199,693,000	210,827,000	232,985,000
Costs of purchased natural gas									0	3,147,000	51,682,000
Selling and general expenses									137,300,000	112,900,000	118,900,000
Exploration expenses
Geological and geophysical									36,000,000.0	27,200,000	26,100,000
Dry holes and previously suspended exploration costs									30,100,000	73,200,000	169,800,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									45,600,000	33,100,000	38,900,000
Total exploration expenses									111,670,000	133,538,000	234,776,000
Depreciation, depletion and amortization									977,800,000	865,800,000	861,500,000
Impairment of assets					28,400,000			34,500,000	115,002,000	62,909,000	0
Accretion of asset retirement obligations									57,730,000	52,511,000	46,059,000
Other operating expenses (income)									13,900,000	11,000,000.0	46,400,000
Interest income									(13,500,000)	(34,200,000)	(12,600,000)
Interest expense, net of capitalization									96,072,000	105,926,000	112,373,000
Income tax expense (benefit)
Current income tax expense (benefit)									9,879,000	5,838,000	16,098,000
Deferred income tax expense (benefit)									34,700,000	72,500,000	179,800,000
Total income tax expense									44,600,000	78,300,000	196,000,000.0
Other segment costs									37,700,000	(36,700,000)	21,000,000.0
Net income including noncontrolling interest	22,600,000	$ (8,300,000)	$ 35,100,000	$ 89,400,000	64,400,000	$ 151,100,000	$ 156,300,000	$ 114,700,000	138,799,000	486,485,000	723,681,000
Additions to property, plant, equipment									1,118,100,000	840,600,000	914,800,000
Total assets at year-end	9,832,626,000				9,667,479,000				9,832,626,000	9,667,479,000	9,766,700,000
Maximum
Income tax expense (benefit)
Current income tax expense (benefit)											16,200,000
Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,689,845,000	3,014,856,000	3,376,639,000
Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	3,742,000	72,215,000
Operating Segments
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									17,600,000	6,000,000.0	8,000,000.0
Total revenues and other income									2,707,400,000	3,024,600,000	3,456,800,000
Lease operating expenses
Lease operating expenses and taxes other than income									572,800,000	649,700,000	678,900,000
Repair and maintenance									65,900,000	68,500,000	58,200,000
Workovers									126,500,000	218,800,000	47,300,000
Total lease operating expenses									765,200,000	937,000,000.0	784,400,000
Severance and ad valorem taxes									39,200,000	39,200,000	42,800,000
Transportation, gathering and processing									199,700,000	210,800,000	233,000,000.0
Costs of purchased natural gas										3,100,000	51,700,000
Selling and general expenses									46,200,000	23,800,000	37,700,000
Exploration expenses
Geological and geophysical									36,000,000.0	27,200,000	26,100,000
Dry holes and previously suspended exploration costs									30,100,000	73,200,000	169,800,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									45,600,000	33,100,000	38,900,000
Total exploration expenses									111,700,000	133,500,000	234,800,000
Depreciation, depletion and amortization									969,400,000	856,900,000	850,500,000
Impairment of assets									115,000,000.0	62,900,000
Accretion of asset retirement obligations									57,600,000	52,400,000	46,000,000.0
Other operating expenses (income)									11,700,000	14,200,000	50,800,000
Interest income									(1,700,000)	(22,000,000.0)	(3,300,000)
Interest expense, net of capitalization									400,000	800,000	500,000
Income tax expense (benefit)
Current income tax expense (benefit)									11,700,000	4,900,000	7,400,000
Deferred income tax expense (benefit)									78,500,000	101,400,000	230,400,000
Total income tax expense									90,200,000	106,300,000	237,800,000
Other segment costs									6,100,000	7,300,000	8,900,000
Net income including noncontrolling interest									296,700,000	598,400,000	881,200,000
Additions to property, plant, equipment									1,096,900,000	811,400,000	890,600,000
Total assets at year-end	9,369,400,000				9,175,600,000				9,369,400,000	9,175,600,000	9,400,200,000
Operating Segments \| United States
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									5,900,000	4,500,000	6,500,000
Total revenues and other income									2,159,800,000	2,508,300,000	2,928,300,000
Lease operating expenses
Lease operating expenses and taxes other than income									391,400,000	471,300,000	532,300,000
Repair and maintenance									60,800,000	63,700,000	53,200,000
Workovers									124,900,000	214,900,000	45,200,000
Total lease operating expenses									577,100,000	749,900,000	630,700,000
Severance and ad valorem taxes									37,700,000	37,800,000	41,400,000
Transportation, gathering and processing									107,000,000.0	130,900,000	157,000,000.0
Costs of purchased natural gas										0	0
Selling and general expenses									13,700,000	(3,300,000)	11,800,000
Exploration expenses
Geological and geophysical									27,200,000	14,400,000	6,600,000
Dry holes and previously suspended exploration costs									(900,000)	70,900,000	153,100,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									14,700,000	10,900,000	14,900,000
Total exploration expenses									41,000,000.0	96,200,000	174,600,000
Depreciation, depletion and amortization									822,100,000	709,200,000	706,000,000.0
Impairment of assets									115,000,000.0	62,900,000
Accretion of asset retirement obligations									46,600,000	43,100,000	37,800,000
Other operating expenses (income)									10,800,000	9,300,000	27,200,000
Interest income									(1,700,000)	(22,000,000.0)	(3,300,000)
Interest expense, net of capitalization									100,000	200,000	100,000
Income tax expense (benefit)
Current income tax expense (benefit)									800,000	1,500,000	3,100,000
Deferred income tax expense (benefit)									76,900,000	123,800,000	229,600,000
Total income tax expense									77,700,000	125,300,000	232,700,000
Other segment costs									4,200,000	6,900,000	7,200,000
Net income including noncontrolling interest									308,500,000	561,900,000	905,100,000
Additions to property, plant, equipment									763,500,000	601,700,000	671,300,000
Total assets at year-end	6,771,300,000				6,953,800,000				6,771,300,000	6,953,800,000	7,107,000,000
Operating Segments \| Canada
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									1,700,000	1,500,000	1,500,000
Total revenues and other income									531,900,000	509,700,000	517,500,000
Lease operating expenses
Lease operating expenses and taxes other than income									178,900,000	176,800,000	144,700,000
Repair and maintenance									5,100,000	4,800,000	5,000,000.0
Workovers									1,600,000	3,900,000	2,100,000
Total lease operating expenses									185,600,000	185,500,000	151,800,000
Severance and ad valorem taxes									1,500,000	1,400,000	1,400,000
Transportation, gathering and processing									92,700,000	79,900,000	76,000,000.0
Costs of purchased natural gas										3,100,000	51,700,000
Selling and general expenses									23,700,000	20,400,000	16,500,000
Exploration expenses
Geological and geophysical									100,000	200,000	100,000
Dry holes and previously suspended exploration costs									0	0	0
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									300,000	300,000	400,000
Total exploration expenses									400,000	500,000	500,000
Depreciation, depletion and amortization									144,800,000	146,000,000.0	142,200,000
Impairment of assets									0	0
Accretion of asset retirement obligations									10,300,000	8,600,000	7,800,000
Other operating expenses (income)									1,800,000	2,800,000	15,500,000
Interest income									0	0	0
Interest expense, net of capitalization									100,000	400,000	200,000
Income tax expense (benefit)
Current income tax expense (benefit)									10,600,000	3,200,000	3,700,000
Deferred income tax expense (benefit)									4,000,000.0	8,800,000	7,500,000
Total income tax expense									14,600,000	12,000,000.0	11,200,000
Other segment costs									1,600,000	100,000	1,100,000
Net income including noncontrolling interest									54,800,000	49,000,000.0	41,600,000
Additions to property, plant, equipment									152,500,000	137,900,000	206,200,000
Total assets at year-end	2,000,000,000				1,919,800,000				2,000,000,000	1,919,800,000	2,080,000,000
Operating Segments \| Other
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									10,000,000.0	0	0
Total revenues and other income									15,700,000	6,600,000	11,000,000.0
Lease operating expenses
Lease operating expenses and taxes other than income									2,500,000	1,600,000	1,900,000
Repair and maintenance									0	0	0
Workovers									0	0	0
Total lease operating expenses									2,500,000	1,600,000	1,900,000
Severance and ad valorem taxes									0	0	0
Transportation, gathering and processing									0	0	0
Costs of purchased natural gas										0	0
Selling and general expenses									8,800,000	6,700,000	9,400,000
Exploration expenses
Geological and geophysical									8,700,000	12,600,000	19,400,000
Dry holes and previously suspended exploration costs									31,000,000.0	2,300,000	16,700,000
Other exploratory costs, including undeveloped lease amortization and delay lease rentals									30,600,000	21,900,000	23,600,000
Total exploration expenses									70,300,000	36,800,000	59,700,000
Depreciation, depletion and amortization									2,500,000	1,700,000	2,300,000
Impairment of assets									0	0
Accretion of asset retirement obligations									700,000	700,000	400,000
Other operating expenses (income)									(900,000)	2,100,000	8,100,000
Interest income									0	0	0
Interest expense, net of capitalization									200,000	200,000	200,000
Income tax expense (benefit)
Current income tax expense (benefit)									300,000	200,000	600,000
Deferred income tax expense (benefit)									(2,400,000)	(31,200,000)	(6,700,000)
Total income tax expense									(2,100,000)	(31,000,000.0)	(6,100,000)
Other segment costs									300,000	300,000	600,000
Net income including noncontrolling interest									(66,600,000)	(12,500,000)	(65,500,000)
Additions to property, plant, equipment									180,900,000	71,800,000	13,100,000
Total assets at year-end	598,100,000				302,000,000.0				598,100,000	302,000,000.0	213,300,000
Operating Segments \| Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,689,800,000	3,014,900,000	3,376,600,000
Operating Segments \| Revenue from production \| United States
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,153,900,000	2,503,800,000	2,921,800,000
Operating Segments \| Revenue from production \| Canada
Segment Reporting Information [Line Items]
Revenue from contracts with customers									530,200,000	504,500,000	443,800,000
Operating Segments \| Revenue from production \| Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers									5,700,000	6,600,000	11,000,000.0
Operating Segments \| Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers										3,700,000	72,200,000
Operating Segments \| Sales of purchased natural gas \| United States
Segment Reporting Information [Line Items]
Revenue from contracts with customers										0	0
Operating Segments \| Sales of purchased natural gas \| Canada
Segment Reporting Information [Line Items]
Revenue from contracts with customers										3,700,000	72,200,000
Operating Segments \| Sales of purchased natural gas \| Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers										0	0
Corporate, and Discontinued Operations
Segment Reporting Information [Line Items]
Gain on sales of assets and other operating income									13,800,000	3,900,000	3,300,000
Total revenues and other income									13,800,000	3,900,000	3,300,000
Lease operating expenses
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
Selling and general expenses									91,100,000	89,100,000	81,200,000
Exploration expenses
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
Total exploration expenses									0	0	0
Depreciation, depletion and amortization									8,400,000	8,900,000	11,000,000.0
Impairment of assets									0	0
Accretion of asset retirement obligations									100,000	100,000	100,000
Other operating expenses (income)									2,200,000	(3,200,000)	(4,400,000)
Interest income									(11,800,000)	(12,200,000)	(9,300,000)
Interest expense, net of capitalization									95,700,000	105,100,000	111,900,000
Income tax expense (benefit)
Current income tax expense (benefit)									(1,800,000)	900,000	8,800,000
Deferred income tax expense (benefit)									(43,800,000)	(28,900,000)	(50,600,000)
Total income tax expense									(45,600,000)	(28,000,000.0)	(41,800,000)
Other segment costs									31,600,000	(44,000,000.0)	12,100,000
Net income including noncontrolling interest									(157,900,000)	(111,900,000)	(157,500,000)
Additions to property, plant, equipment									21,200,000	29,200,000	24,200,000
Total assets at year-end	$ 463,200,000				$ 491,900,000				463,200,000	491,900,000	366,500,000
Corporate, and Discontinued Operations \| Revenue from production
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ 0	0	0
Corporate, and Discontinued Operations \| Sales of purchased natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers										$ 0	$ 0

Employee and Retiree Benefit Plans - Schedule of Amount Related to Foreign Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	$ 527,079	$ 492,120
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	110,281	103,445
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	659,494	655,324	$ 699,151
Fair value of plan assets at December 31	527,079	492,120	477,809
Net plan liabilities recognized	(132,415)	(163,204)
Net periodic benefit (credit) expense	14,886	19,174	18,458
Pension Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	109,883	115,428
Fair value of plan assets at December 31	110,280	103,445
Net plan liabilities recognized	397	(11,983)
Net periodic benefit (credit) expense	2,131	1,480
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	63,399	54,994	63,808
Fair value of plan assets at December 31	0	0	0
Net plan liabilities recognized	(63,399)	(54,994)
Net periodic benefit (credit) expense	(71)	(759)	$ (308)
Other Postretirement Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	90	106
Fair value of plan assets at December 31	0	0
Net plan liabilities recognized	(90)	(106)
Net periodic benefit (credit) expense	$ (35)	$ (44)

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Paragraph 5
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/exampleRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
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-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
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Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Assets and Liabilities Measured at Fair Value (Tables)

12 Months Ended

Dec. 31, 2025

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, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total





Liabilities:
Nonqualified employee savings plan	$	22,205	$	—	$	—	$	22,205	$	19,469	$	—	$	—	$	19,469


Commodity swaps	—		—		—		—		—		1,707		—		1,707
	$	22,205	$	—	$	—	$	22,205	$	19,469	$	1,707	$	—	$	21,176

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, 2025 and 2024. 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 minimal.


	December 31,
	2025				2024
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,385,080	$	1,326,101	$	1,275,374	$	1,185,961

Schedule of Fair Value Measurements, Nonrecurring

The fair value information associated with the impaired properties is presented in the following tables.


	Year Ended December 31, 2025
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3








Assets:
Impaired proved properties
United States - Offshore	$	—	$	—	$	42,397	$	157,399	$	115,002


	Year Ended December 31, 2024
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3








Assets:
Impaired proved properties
United States - Offshore	$	—	$	—	$	501	$	63,410	$	62,909

Net Income (Loss) Per Common Share (Details) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Earnings Per Share [Abstract]
Basic method (in shares)									143,124,118	150,011,458	155,233,560
Dilutive stock options (in shares)									901,204	1,015,894	1,412,869
Diluted method (in shares)									144,025,322	151,027,352	156,646,429
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations (in USD per share)	$ 0.08	$ (0.02)	$ 0.15	$ 0.51	$ 0.35	$ 0.93	$ 0.84	$ 0.60	$ 0.73	$ 2.73	$ 4.27
Discontinued operations (in USD per share)									0	(0.02)	(0.01)
Net income (in USD per share)	0.08	(0.02)	0.16	0.51	0.35	0.93	0.84	0.59	0.73	2.71	4.26
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations (in USD per share)	0.08	(0.02)	0.15	0.50	0.34	0.93	0.83	0.60	0.72	2.72	4.23
Discontinued operations (in USD per share)									0	(0.02)	(0.01)
Net income (in USD per share)	$ 0.08	$ (0.02)	$ 0.16	$ 0.50	$ 0.34	$ 0.93	$ 0.83	$ 0.59	$ 0.72	$ 2.70	$ 4.22

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, 2022				$ 893,578	$ 6,055,498	$ (534,686)	$ (1,614,717)	$ 154,119
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock transactions and other				(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 gain (loss), net of income taxes	36,598					36,598
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				(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 gain (loss), net of income taxes	(134,692)					(134,692)
Retirement and postretirement benefit plans, net of income taxes						27,737
Repurchase of common stock							(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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock transactions and other				(32,165)
Share-based compensation				42,848
Net income attributable to Murphy	104,234				104,234			34,565
Cash dividends paid					(186,205)
Foreign currency translation gain (loss), net of income taxes	73,993					73,993
Retirement and postretirement benefit plans, net of income taxes						(148)
Repurchase of common stock	(100,000)						(100,849)
Awarded restricted stock, net of forfeitures							22,422
Distributions to noncontrolling interest owners								(63,841)
Balance at end of year at Dec. 31, 2025	$ 5,236,697	$ 5,118,380	$ 195,101	$ 859,633	$ 6,691,318	$ (554,227)	$ (2,073,445)	$ 118,317

Income Taxes - Schedule of Effective Income Tax Rates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount
Income tax expense based on the U.S. statutory tax rate	$ 38,402	$ 119,190	$ 193,424
Tax effect on income attributable to NCI	(7,259)	(16,656)	(13,046)
U.S. tax benefit on certain foreign upstream investments	0	(33,677)	0
Other	(397)	2,398	(293)
Share-based payment awards	5,595	2,340	2,636
State and Local Income Taxes, Net of Federal Income Tax Effect	(589)	(3,546)	4,725
Other	(5,825)	(532)	1,377
Worldwide Changes in Unrecognized Tax Benefits	(1,828)	1,952	2,456
Total income tax expense	$ 44,552	$ 78,272	$ 195,921
Percent
Income tax expense based on the U.S. statutory tax rate	21.00%	21.00%	21.00%
Tax effect on income attributable to NCI	(4.00%)	(2.90%)	(1.40%)
U.S. tax benefit on certain foreign upstream investments	0	(0.059)	0
Other	(0.20%)	0.40%	0.00%
Share-based payment awards	3.10%	0.40%	0.30%
State and Local Income Taxes, Net of Federal Income Tax Effect	(0.30%)	(0.60%)	0.50%
Other	(3.20%)	(0.20%)	0.10%
Worldwide Changes in Unrecognized Tax Benefits	(1.00%)	0.30%	0.30%
Effective Tax Rate	24.40%	13.80%	21.30%
Canada
Amount
Research and development tax credits	$ (3,875)	$ (3,547)	$ (3,982)
Statutory tax rate differential	$ 2,629	$ 5,428	$ 3,732
Percent
Research and development tax credits	(2.10%)	(0.60%)	(0.40%)
Statutory tax rate differential	1.40%	1.00%	0.40%
Other Foreign jurisdictions
Amount
Statutory tax rate differential	$ 4,960	$ 9,127	$ 2,844
Changes in valuation allowances	$ (2,922)	$ 2,636	$ 10,853
Percent
Statutory tax rate differential	2.70%	1.60%	0.30%
Changes in valuation allowances	(1.60%)	0.50%	1.20%
Côte d’Ivoire
Amount
Changes in valuation allowances	$ 13,140	$ 0	$ 0
Percent
Changes in valuation allowances	7.20%	0.00%	0.00%
United States
Amount
Research and development tax credits	$ 2,521	$ (6,841)	$ (8,805)
Percent
Research and development tax credits	1.40%	(1.20%)	(1.00%)

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Unrecognized Tax Benefits [Roll Forward]
Balance at January 1	$ 9,979	$ 6,384	$ 3,928
Additions for tax positions related to current year	0	1,643	0
Additions for tax positions related to prior year	0	1,952	2,456
Reductions for tax positions related to prior year	(882)	0	0
Settlements with taxing authorities	(946)	0	0
Balance at December 31	$ 8,151	$ 9,979	$ 6,384

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2025

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, 2025					December 31, 2024
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production ¹	$	23,042,373	$	8,099,291	2	$	21,716,358	$	8,021,620	2
Corporate and other	162,122		37,055			149,834		33,033
Property, plant and equipment	$	23,204,495	$	8,136,346		$	21,866,192	$	8,054,653
¹ Includes unproved mineral rights as follows:	$	229,759	$	99,729		$	283,015	$	151,341

2 Includes $12,050 in 2025 and $13,335 in 2024 related to administrative assets and support equipment.

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, 2025, 2024 and 2023, the Company had total capitalized drilling costs pending the determination of proved reserves of $191.8 million, $72.1 million and $49.1 million, respectively. The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented.


(Thousands of dollars)	2025		2024		2023
Beginning balance at January 1	$	72,055	$	49,118	$	171,860
Additions pending the determination of proved reserves	119,766		49,408		48
Reclassifications to proved properties based on the determination of proved reserves	—		—		(82,185)

Capitalized exploration well costs charged to expense	—		(26,471)		(40,605)
Ending balance at December 31	$	191,821	$	72,055	$	49,118

Capital additions of $119.8 million, for the year ended December 31, 2025, were mainly for the Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well, in Vietnam, encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations. Capital additions also included Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and Bubale-1X (Block CI-709) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire.

Subsequent to year end, Murphy announced the successful discoveries of the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells, which encountered 50 feet and 30 feet of net pay, respectively. The Company also announced the results of two exploration wells in Côte d’Ivoire at the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and at the Caracal-1X (Block CI-102) exploration well, which will be plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. A portion of the Civette-1X dry hole charge was recorded in 2025. The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026.

Capital additions of $49.4 million, for the year ended December 31, 2024, were 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.

Reclassifications to proved properties of $82.2 million, for the year ended December 31, 2023, were primarily related to Lac Da Vang-4X (Golden Camel), Block 15-1/05 exploration well in Vietnam.

Capitalized well costs charged to dry hole expense were $26.5 million and $40.6 million for the years ended 2024 and 2023, respectively. In 2024, costs related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well. In 2023, costs related to the Cholula-1EXP well offshore Mexico and the Oso #1 (Atwater Valley 138) and Chinook #7 (Walker Ridge 425) exploration wells in the Gulf of America.

The preceding table excludes well costs of $30.1 million, $46.7 million, and $129.2 million incurred and expensed directly to dry hole during the years ended 2025, 2024 and 2023, respectively. In 2025, these costs primarily included $30.0 million for the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire. In 2024, these costs primarily included $27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $13.4 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America. In 2023, the amount primarily included $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.


	2025			2024			2023
(Thousands of dollars)	Amount		No. of Wells		Amount		No. of Wells	Amount		No. of Wells
Aging of capitalized well costs
Zero to one year	$	28,384	2		$	49,790	5	$	—	0
One to two years	140,959		6		—		—	—		0
Two to three years	—		—		—		—	2,698		1
Three years or more	22,478		3		22,265		3	46,420		3
	$	191,821	11		$	72,055	8	$	49,118	4

Of the $163.4 million of exploratory well costs capitalized more than one year at December 31, 2025, $91.5 million was in Vietnam, $64.6 million was in the Gulf of America, $4.6 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.

Property Additions

On July 1, 2025, the Company purchased additional working interests in the Eagle Ford Shale, in acreages primarily operated by Murphy, for $23.0 million.

During the first quarter of 2025, Murphy purchased the Pioneer FPSO from BW Offshore (UK) Limited for a gross purchase price of $125.0 million. The FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a new five-year contract.

Dispositions

In the fourth quarter of 2025, Murphy received a $12.5 million payment for achieving the first milestone related to the contingent sale of Brunei CA-2 in 2022, which resulted in a $4.0 million gain on sale of assets. In addition, the revaluation of the final milestone (anticipated in 2031) resulted in a $6.0 million gain on sale of assets.

In September 2025, Murphy executed a purchase and sale agreement, which closed in October 2025, for the sale of leases in the Ralph and Saylee area of Tilden West for an adjusted sales price of $8.2 million. No gain or loss was recorded for this sale.

Impairments

In 2025, the Company recognized a pretax impairment charge of $115.0 million ($92.0 million excluding NCI) related to the partial write-down of the Dalmatian field, in the Gulf of America, due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

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.

Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Inventory Disclosure [Abstract]
Unsold crude oil	$ 17,560	$ 18,745
Materials and supplies	39,724	36,113
Inventories	$ 57,284	$ 54,858

Other Financial Information

12 Months Ended

Dec. 31, 2025

Other Financial Information [Abstract]

Other Financial Information

Note M – Other Financial Information

Gain (Loss) 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 $29.4 million loss in 2025, $45.4 million gain in 2024 and $10.8 million loss in 2023.

Supplemental Information to Statements of Cash Flows


(Thousands of dollars)	2025		2024		2023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(75,437)	$	71,081	$	47,151
(Increase) decrease in inventories	(1,461)		1,327		329
(Increase) decrease in prepaid expenses	539		1,192		(1,293)
Increase (decrease) in accounts payable and accrued liabilities 1	3,101		3,287		(140,011)
Increase (decrease) in income taxes payable	(794)		(2,004)		(5,537)
Net (increase) decrease in noncash working capital	$	(74,052)	$	74,883	$	(99,361)

Supplementary disclosures:

Interest paid, net of amounts capitalized of $8.8 million in 2025, $11.4 million in 2024 and $14.5 million in 2023	88,119		78,806		108,912

Non-cash investing activities:
Asset retirement costs capitalized	$	9,629	$	47,233	$	32,975
(Increase) decrease in capital expenditure accrual	(98,778)		(5,935)		17,517

1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments.

Leases - Schedule of Lease Term and Discount Rate (Details)	Dec. 31, 2025	Dec. 31, 2024
Weighted average remaining lease term:
Operating leases	7 years	8 years
Finance leases	5 years	6 years
Weighted average discount rate:
Operating leases	5.50%	5.70%
Finance leases	5.40%	4.90%

Financial Instruments and Risk Management - Schedule of Fair Value of Derivative Instruments Not Designated as Hedging Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Not Designated as Hedging Instrument \| Commodity swaps \| Accounts payable
Derivatives, Fair Value [Line Items]
Liability	$ 0	$ (1,707)

- Definition

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References + Details

Asset Retirement Obligations - Schedule of Classification of Asset of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Balance at end of period	$ 1,012,867	$ 1,008,884	$ 914,763
Current portion of liability	(41,959)	(48,080)
Asset retirement obligations	$ 970,908	$ 960,804

Financing Arrangements and Debt (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025		2024
Notes payable

5.875% notes, due December 2027	$	78,899	$	78,899
6.375% notes, due July 2028	148,590		148,590
7.050% notes, due May 2029	117,582		117,582
6.000% notes, due October 2032	600,000		600,000
5.875% notes, due December 2042 ¹	339,761		339,761

Total notes payable	1,284,832		1,284,832
Unamortized debt issuance cost and discount on notes payable	(12,406)		(14,336)
Total notes payable, net of unamortized discount	1,272,426		1,270,496
Finance lease obligations, due through November 2034	12,654		4,877
Total debt including current maturities	1,285,080		1,275,373
Senior Unsecured Revolving Credit Facility	100,000		—
Current maturities	(2,514)		(871)
Total long-term debt	$	1,382,566	$	1,274,502

1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.

Environmental and Other Contingencies (Details) $ in Millions	Dec. 31, 2025 USD ($)
Environmental Remediation Obligations [Abstract]
Threshold for disclosure of monetary sanctions related to environmental proceedings	$ 1.0
Threshold for disclosure of monetary sanctions related to aware of legal environmental proceedings	$ 1.0

Commitments (Details) $ in Thousands	Dec. 31, 2025 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	$ 315,609
Future rental payments, due year two	146,130
Future rental payments, due year three	63,009
Future rental payments, due year four	60,214
Future rental payments, due year five	58,445
Commitments for capital expenditures	551,200
Gulf of America
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	245,300
Eagle Ford Shale
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	82,600
Canada
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	49,800
Vietnam
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	127,500
Côte d’Ivoire
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	45,000
Processing production handling and transportation services
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	132,800
Future rental payments, due year two	107,300
Future rental payments, due year three	97,600
Future rental payments, due year four	66,300
Future rental payments, due year five	45,800
Development Activities
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, due year one	23,600
Future rental payments, due year two	23,100
Future rental payments, due year three	24,000
Future rental payments, due year four	23,900
Future rental payments, due year five	$ 24,200

Net Income (Loss) Per Common Share (Tables)

12 Months Ended

Dec. 31, 2025

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, except per share amounts)	2025		2024		2023
Basic method	143,124,118		150,011,458		155,233,560
Dilutive restricted stock units	901,204		1,015,894		1,412,869
Diluted method	144,025,322		151,027,352		156,646,429
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	0.73	$	2.73	$	4.27
Discontinued operations	—		(0.02)		(0.01)
Net income	$	0.73	$	2.71	$	4.26
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	0.72	$	2.72	$	4.23
Discontinued operations	—		(0.02)		(0.01)
Net income	$	0.72	$	2.70	$	4.22

Supplemental Quarterly Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Quarterly Financial Information Disclosure [Abstract]

Schedule of Supplemental Quarterly Information


(Millions of dollars except per share amounts)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
Year ended December 31, 2025
Revenue from contracts with customers 1	$	672.7	$	683.0	$	721.0	$	613.1	$	2,689.8
Income (loss) from continuing operations before income taxes 1	122.8		34.9		(3.7)		28.9		182.9
Income (loss) from continuing operations 1	90.0		33.8		(7.8)		22.3		138.3
Net income (loss) including noncontrolling interest	89.4		35.1		(8.3)		22.6		138.8
Net income (loss) attributable to Murphy	73.0		22.3		(3.0)		11.9		104.2
Income (loss) from continuing operations per common share ²
Basic	0.51		0.15		(0.02)		0.08		0.73
Diluted	0.50		0.15		(0.02)		0.08		0.72
Net income (loss) per common share ²
Basic	0.51		0.16		(0.02)		0.08		0.73
Diluted	0.50		0.16		(0.02)		0.08		0.72
Cash dividend per common share	0.325		0.325		0.325		0.325		1.300
Year ended December 31, 2024
Revenue from contracts with customers 1	$	794.8	$	801.0	$	753.2	$	669.6	$	3,018.6
Income from continuing operations before income taxes 1	145.6		189.6		153.8		78.6		567.6
Income from continuing operations 1	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

1 “Revenue from contracts with customers”, “Income (loss) from continuing operations before income taxes”, “Income (loss) from continuing operations” and “Net income (loss) including noncontrolling interest” includes 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.

Financial Instruments and Risk Management - Schedule of Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Not Designated as Hedging Instrument \| Commodity swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 5,927	$ (1,707)	$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
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-Section 55
-Paragraph 182
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-182

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (a)(4)
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-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Section 50
-Paragraph 4D
-Subparagraph (a)(3)
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Section 50
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues
Revenues	$ 2,689,800	$ 3,018,600	$ 3,448,900
Other operating revenues	17,600	6,000	7,900
Total revenues	2,707,400	3,024,500	3,456,800
Costs and expenses
Lease operating expenses	765,200	937,000	784,400
Severance and ad valorem taxes	39,200	39,200	42,800
Transportation, gathering and processing	199,693	210,827	232,985
Costs of purchased natural gas	0	3,147	51,682
Exploration costs charged to expense	100,000	123,900	223,900
Undeveloped lease amortization	11,700	9,600	10,900
Depreciation, depletion and amortization	969,400	856,900	850,500
Accretion of asset retirement obligations	57,600	52,400	46,000
Impairment of assets	115,000	62,900
Selling and general expenses	46,200	23,800	37,700
Other expenses (benefits)	16,500	300	56,900
Total costs and expenses	2,320,500	2,319,900	2,337,800
Results of operations before taxes	386,900	704,600	1,119,000
Income tax expense (benefit)	90,200	106,300	237,800
Results of operations	296,700	598,400	881,200
Crude Oil and Natural Gas Liquids
Revenues
Revenues	2,307,500	2,714,900	3,005,800
Natural Gas
Revenues
Revenues	382,300	300,000	370,900
Sales of purchased natural gas
Revenues
Revenues		3,700	72,200
United States
Revenues
Revenues	2,153,900	2,503,800	2,921,800
Other operating revenues	5,900	4,500	6,500
Total revenues	2,159,800	2,508,300	2,928,300
Costs and expenses
Lease operating expenses	577,100	749,900	630,700
Severance and ad valorem taxes	37,700	37,800	41,400
Transportation, gathering and processing	107,000	130,900	157,000
Costs of purchased natural gas		0	0
Exploration costs charged to expense	33,500	90,000	166,500
Undeveloped lease amortization	7,500	6,200	8,100
Depreciation, depletion and amortization	822,100	709,200	706,000
Accretion of asset retirement obligations	46,600	43,100	37,800
Impairment of assets	115,000	62,900
Selling and general expenses		(3,300)
Selling and general expenses	13,700		11,800
Other expenses (benefits)	13,400	(5,600)	31,200
Total costs and expenses	1,773,600	1,821,100	1,790,500
Results of operations before taxes	386,200	687,200	1,137,800
Income tax expense (benefit)	77,700	125,300	232,700
Results of operations	308,500	561,900	905,100
United States \| Crude Oil and Natural Gas Liquids
Revenues
Revenues	2,047,400	2,436,000	2,829,100
United States \| Natural Gas
Revenues
Revenues	106,500	67,800	92,700
United States \| Sales of purchased natural gas
Revenues
Revenues		0	0
Canada \| Conventional gas
Revenues
Revenues	530,200	508,200	516,100
Other operating revenues	1,700	1,500	1,400
Total revenues	531,900	509,700	517,500
Costs and expenses
Lease operating expenses	185,600	185,500	151,800
Severance and ad valorem taxes	1,500	1,400	1,400
Transportation, gathering and processing	92,700	79,900	76,000
Costs of purchased natural gas		3,100	51,700
Exploration costs charged to expense	300	400	400
Undeveloped lease amortization	100	100	100
Depreciation, depletion and amortization	144,800	146,000	142,200
Accretion of asset retirement obligations	10,300	8,600	7,800
Impairment of assets	0	0
Selling and general expenses	23,700	20,400	16,500
Other expenses (benefits)	3,500	3,300	16,800
Total costs and expenses	462,500	448,700	464,700
Results of operations before taxes	69,400	61,000	52,800
Income tax expense (benefit)	14,600	12,000	11,200
Results of operations	54,800	49,000	41,600
Canada \| Crude Oil and Natural Gas Liquids \| Conventional gas
Revenues
Revenues	254,400	272,300	165,700
Canada \| Natural Gas \| Conventional gas
Revenues
Revenues	275,800	232,200	278,200
Canada \| Sales of purchased natural gas \| Conventional gas
Revenues
Revenues		3,700	72,200
Other
Revenues
Revenues	5,700	6,600	11,000
Other operating revenues	10,000	0	0
Total revenues	15,700	6,600	11,000
Costs and expenses
Lease operating expenses	2,500	1,600	1,900
Severance and ad valorem taxes	0	0	0
Transportation, gathering and processing	0	0	0
Costs of purchased natural gas		0	0
Exploration costs charged to expense	66,200	33,500	57,000
Undeveloped lease amortization	4,100	3,300	2,700
Depreciation, depletion and amortization	2,500	1,700	2,300
Accretion of asset retirement obligations	700	700	400
Impairment of assets	0	0
Selling and general expenses	8,800	6,700	9,400
Other expenses (benefits)	(400)	2,600	8,900
Total costs and expenses	84,400	50,100	82,600
Results of operations before taxes	(68,700)	(43,500)	(71,600)
Income tax expense (benefit)	(2,100)	(31,000)	(6,100)
Results of operations	(66,600)	(12,500)	(65,500)
Other \| Crude Oil and Natural Gas Liquids
Revenues
Revenues	5,700	6,600	11,000
Other \| Natural Gas
Revenues
Revenues	$ 0	0	0
Other \| Sales of purchased natural gas
Revenues
Revenues		$ 0	$ 0

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2025
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 Income Tax Disclosures. In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The 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. The Company adopted this standard in the fourth quarter of 2025. The adoption did not affect the calculation of income tax expense. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note H. 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 are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impacts on our results of operations, cash flows and financial condition. The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)(1)
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-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)(iv)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (h)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 5
-Subparagraph (SAB Topic 11.M.Q2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480530/250-10-S99-5

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 6
-Subparagraph (i)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480528/815-20-65-6

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479654/326-10-65-4

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479654/326-10-65-4

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480530/250-10-S99-6

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (f)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 250
-Publisher FASB
-URI https://asc.fasb.org/250/tableOfContent

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480175/815-40-65-1

+ Details

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
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 IT group, which oversees the Company’s IT and 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 (CIO) oversees the IT group and, either personally or through a designated representative, serves as a member of the IMT. The CIO reports directly to the Chief Technology Officer who briefs 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. To our knowledge, Murphy has not experienced any cybersecurity incidents that have had, or are likely to have, material impacts to our business, operations, finances, or reputation
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 (CIO) oversees the IT group and, either personally or through a designated representative, serves as a member of the IMT. The CIO reports directly to the Chief Technology Officer who briefs 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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025		2024		2023
Income (loss) from continuing operations before income taxes
United States	$	195,245	$	468,202	$	901,761
Foreign	(12,379)		99,367		19,308
Total	$	182,866	$	567,569	$	921,069
Income tax expense
Current tax expense

U.S. State and Local	$	468	$	1,153	$	2,916
Foreign	9,411		4,685		13,182
Total current tax expense	9,879		5,838		16,098
Deferred tax expense
U.S. Federal	37,825		55,377		170,115
U.S. State and Local	(1,214)		(5,641)		3,706
Foreign	(1,938)		22,698		6,002
Total deferred tax expense	34,673		72,434		179,823
Total income tax expense
U.S. Federal	37,825		55,377		170,115
U.S. State and Local	(746)		(4,488)		6,622
Foreign	7,473		27,383		19,184
Total income tax expense	$	44,552	$	78,272	$	195,921

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)	2025				2024				2023
	Amount		Percent		Amount		Percent		Amount		Percent
Income tax expense based on the U.S. statutory tax rate	$	38,402	21.0	%	$	119,190	21.0	%	$	193,424	21.0	%
Domestic Federal
Tax Credits
Research and development tax credits	2,521		1.4		(6,841)		(1.2)		(8,805)		(1.0)
Nontaxable or Nondeductible Items
Tax effect on income attributable to NCI	(7,259)		(4.0)		(16,656)		(2.9)		(13,046)		(1.4)
U.S. tax benefit on certain foreign upstream investments	—		—		(33,677)		(5.9)		—		—
Other	(397)		(0.2)		2,398		0.4		(293)		—

Share-based payment awards	5,595		3.1		2,340		0.4		2,636		0.3

State and Local Income Taxes, Net of Federal Income Tax Effect 1	(589)		(0.3)		(3,546)		(0.6)		4,725		0.5
Foreign Tax Effects
Canada
Statutory tax rate differential	2,629		1.4		5,428		1.0		3,732		0.4
Research and development tax credits	(3,875)		(2.1)		(3,547)		(0.6)		(3,982)		(0.4)



Other Foreign jurisdictions
Statutory tax rate differential	4,960		2.7		9,127		1.6		2,844		0.3
Changes in valuation allowances
Côte d’Ivoire	13,140		7.2		—		—		—		—

Other Foreign Jurisdictions	(2,922)		(1.6)		2,636		0.5		10,853		1.2
Other	(5,825)		(3.2)		(532)		(0.2)		1,377		0.1
Worldwide Changes in Unrecognized Tax Benefits	(1,828)		(1.0)		1,952		0.3		2,456		0.3
Effective Tax Rate	$	44,552	24.4	%	$	78,272	13.8	%	$	195,921	21.3	%

1 State taxes primarily include Texas and Louisiana.

Schedule of Cash Taxes Paid, Net of Refunds

The following table displays cash taxes paid, net of refunds, for each of the three years presented.


(Thousands of dollars)	2025		2024		2023

U.S. State and Local
Alabama	$	(1,868)	$	—	$	4,838
Texas	1,500		2,300		1,079
Other	50		—		51
Total U.S. State and Local	(318)		2,300		5,968
Foreign
Canada	2,929		6,480		3,553
Canada - Alberta	2,809		3,269		1,756
Brunei	681		599		1,079

Total Foreign	6,419		10,348		6,388
Total	$	6,101	$	12,648	$	12,356

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)	2025		2024
Deferred tax assets
Property and leasehold costs	$	235,509	$	225,379
Liabilities for dismantlements	40,242		36,719
Postretirement and other employee benefits	66,418		66,293

U. S. net operating loss	224,956		289,594
Investment in partnership	20,307		9,096
Other deferred tax assets 1	97,660		100,352
Total gross deferred tax assets	685,092		727,433
Less: Valuation allowance	(157,807)		(149,498)
Net deferred tax assets	527,285		577,935
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)		(5,000)
Accumulated depreciation, depletion and amortization	(812,727)		(811,178)

Other deferred tax liabilities 1	(87,895)		(97,547)
Total gross deferred tax liabilities	(905,622)		(913,725)
Net deferred tax (liabilities) assets	$	(378,337)	$	(335,790)

1 Other deferred tax assets and other deferred tax liabilities are primarily comprised of the deferred tax benefit and obligation associated with operating lease liabilities and the associated right of use assets, respectively.

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)	2025		2024		2023
Balance at January 1	$	9,979	$	6,384	$	3,928
Additions for tax positions related to current year	—		1,643		—
Additions for tax positions related to prior year	—		1,952		2,456
Reductions for tax positions related to prior year	(882)		—		—

Settlements with taxing authorities	(946)		—		—

Balance at December 31	$	8,151	$	9,979	$	6,384

Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	$ 5,341,843	$ 5,549,653
Other comprehensive income (loss)	73,845	(106,955)	$ 13,569
Balance at end of year	5,236,697	5,341,843	5,549,653
Total
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(628,072)	(521,117)	(534,686)
Before reclassifications to income	70,360	(110,979)
Reclassifications to income	3,485	4,024
Other comprehensive income (loss)	73,845	(106,955)
Balance at end of year	(554,227)	(628,072)	(521,117)
Foreign Currency Translation Gains (Losses)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning and end of period	(516,324)	(381,632)
Before reclassifications to income	73,993	(134,692)
Reclassifications to income	0	0
Other comprehensive income (loss)	73,993	(134,692)
Balance at end of year	(442,331)	(516,324)	(381,632)
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	(111,748)	(139,485)
Before reclassifications to income	(3,633)	23,713
Reclassifications to income	3,485	4,024
Other comprehensive income (loss)	(148)	27,737
Balance at end of year	(111,896)	(111,748)	$ (139,485)
Reclassification before tax	4,200	5,400
Deferred Loss on Interest Rate Derivative Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Reclassification tax	$ 700	$ 1,400

Financial Instruments and Risk Management - Narrative (Details) - derivative	Dec. 31, 2025	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of foreign currency derivatives held	0	0

Assets and Liabilities Measured at Fair Value - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Carrying Amount
Current and long-term debt, carrying amount	$ 1,385,080	$ 1,275,374
Fair Value
Current and long-term debt, fair value	$ 1,326,101	$ 1,185,961

- Definition

Fair value portion of debt instrument payable, including, but not limited to, notes payable and loans payable.

+ References

+ Details

Leases - Schedule of Other Lease Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2025 USD ($) Drilling_Rig	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 258,564	$ 328,847
Operating cash flows from finance leases	339	311
Financing cash flows from finance leases	1,238	665	$ 622
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	247,566	349,312
Finance leases	$ 8,845	1,749
Number of drilling rigs \| Drilling_Rig	2
Offshore drilling rig
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$ 153,700	254,100
Offshore Two Drilling Rig
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$ 72,200	$ 52,700

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Incentive Plans - Schedule of Changes in Performance-Based Stock Units Outstanding (Details) - Equity-Settled Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	1,392,421	1,818,188	2,148,467
Granted (in shares)	657,730	536,900	409,160
Vested and issued (in shares)	(481,670)	(938,599)	(408,135)
Forfeited (in shares)	(104,966)	(24,068)	(331,304)
Outstanding at end of year (in shares)	1,463,515	1,392,421	1,818,188

Revenue from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 613,100	$ 721,000	$ 683,000	$ 672,700	$ 669,600	$ 753,200	$ 801,000	$ 794,800	$ 2,689,845	$ 3,018,598	$ 3,448,854
Gain (loss) on derivative instruments									5,927	(1,707)	0
Gain on sale of assets and other operating income									23,051	11,583	11,293
Total revenues and other income									2,718,823	3,028,474	3,460,147
Revenue from production
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									2,689,845	3,014,856	3,376,639
Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									2,227,343	2,635,660	2,916,252
Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									80,173	79,165	89,526
Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									382,329	300,031	370,861
Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									0	3,742	72,215
United States - Onshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									617,358	586,584	676,139
United States - Onshore \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									41,518	32,853	33,178
United States - Onshore \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									35,524	17,443	21,346
United States Offshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									1,355,527	1,777,723	2,072,353
United States Offshore \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									33,029	38,858	47,434
United States Offshore \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									70,968	50,329	71,332
Canada - Onshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									61,715	70,855	78,088
Canada - Onshore \| Net natural gas liquids revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									5,626	7,454	8,914
Canada - Onshore \| Net natural gas revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									275,837	232,259	278,183
Canada - Onshore \| Sales of purchased natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									0	3,742	72,215
Canada - Offshore \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									187,030	193,961	78,650
Other \| Net crude oil and condensate revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers									$ 5,713	$ 6,537	$ 11,022

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Operating Activities

Net income including noncontrolling interest

$ 138,799,000

$ 486,485,000

$ 723,681,000

Adjustments to reconcile net income to net cash provided by continuing operations activities

Depreciation, depletion and amortization

977,753,000

865,753,000

861,602,000

Unsuccessful exploration well costs and previously suspended exploration costs

30,095,000

73,201,000

169,795,000

Deferred income tax expense

34,673,000

72,434,000

179,823,000

Impairment of assets

115,002,000

62,909,000

Accretion of asset retirement obligations

57,730,000

52,511,000

46,059,000

Long-term non-cash compensation

45,128,000

45,057,000

61,953,000

Amortization of undeveloped leases

11,634,000

9,587,000

10,925,000

(Income) loss from discontinued operations

(485,000)

2,812,000

1,467,000

Unrealized (gain) loss on derivative instruments

(1,706,000)

1,707,000

Contingent consideration payment

(139,574,000)

Unrealized loss on contingent consideration

7,113,000

Other operating activities, net

(86,763,000)

(18,349,000)

(74,728,000)

Net decrease (increase) in non-cash working capital

(74,052,000)

74,883,000

(99,361,000)

Net cash provided by continuing operations activities

1,247,808,000

1,728,990,000

1,748,755,000

Investing Activities

Property additions and dry hole costs

^[1]

(1,020,611,000)

(900,108,000)

(1,066,015,000)

Acquisition of oil and natural gas properties

^[1]

(29,034,000)

(8,056,000)

(35,578,000)

Proceeds from sales of property, plant and equipment

20,719,000

102,913,000

Net cash required by investing activities

(1,028,926,000)

(908,164,000)

(998,680,000)

Financing Activities

Retirement of debt

(650,112,000)

(498,175,000)

Early redemption of debt cost

(15,700,000)

Debt issuance

600,000,000

Debt issuance cost

(10,145,000)

Borrowings on revolving credit facility

550,000,000

350,000,000

600,000,000

Repayment of revolving credit facility

(450,000,000)

(350,000,000)

(600,000,000)

Issue costs of revolving credit facility

(418,000)

(14,718,000)

(20,000)

Repurchase of common stock

(102,620,000)

(301,350,000)

(150,022,000)

Cash dividends paid

(186,205,000)

(179,961,000)

(170,978,000)

Distributions to noncontrolling interest

(63,841,000)

(118,580,000)

(29,382,000)

Withholding tax on stock-based incentive awards

(9,743,000)

(25,310,000)

(14,276,000)

Finance lease obligation payments

(1,238,000)

(665,000)

(622,000)

Contingent consideration payment

(60,243,000)

Net cash required by financing activities

(264,065,000)

(716,541,000)

(923,718,000)

Effect of exchange rate changes on cash and cash equivalents

(1,190,000)

2,210,000

(1,246,000)

Net increase (decrease) in cash and cash equivalents

(46,373,000)

106,495,000

(174,889,000)

Cash and cash equivalents at beginning of period

423,569,000

317,074,000

491,963,000

Cash and cash equivalents at end of period

$ 377,196,000

$ 423,569,000

$ 317,074,000

[1]	Prior period amounts have been reclassified to conform to current period presentation.

Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Dec. 31, 2025

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 oil and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and 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 2025 were $65.34 per BBL for crude oil (WTI) and $3.39 per MCF for natural gas (Henry Hub). The average prices used for 2024 were $75.48 per BBL for 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 crude oil (WTI) and $2.64 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 rounded to one decimal. 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 oil and natural gas reserves are from consolidated subsidiaries (including NCI) 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, 2025.


	Equivalents
(Millions of barrels of oil equivalent)	Total	United States	Canada	Other
Proved developed and undeveloped reserves:
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	729.0	307.4	408.9	12.7
Revisions of previous estimates	26.0	18.0	7.1	0.9

Extensions and discoveries	43.0	4.9	38.1	—
Purchases of properties	4.3	4.3	—	—
Sale of properties	(3.4)	(3.4)	—	—
Production	(68.9)	(39.3)	(29.5)	(0.1)
December 31, 2025 ¹	730.0	291.9	424.6	13.5
Proved developed reserves:
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	436.2	218.9	217.1	0.2
December 31, 2025 ²	418.9	197.8	220.9	0.2
Proved undeveloped reserves:
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	292.8	88.5	191.8	12.5
December 31, 2025 ³	311.1	94.1	203.7	13.3

1 Total and United States includes proved reserves of 15.0 MMBOE, consisting of 13.9 MMBBL of oil, 0.4 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 13.1 MMBOE, consisting of 12.1 MMBBL of oil, 0.4 MMBBL of NGLs and 3.9 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 1.9 MMBOE, consisting of 1.8 MMBBL of oil and 0.3 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

2025 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices and higher gas prices that increased royalty rates and accelerated royalty incentive payouts in the Tupper Montney.

Extensions and discoveries - In 2025, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions.

2024 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the 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 the 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 the 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 the Tupper Montney.

Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in the 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.


(Millions of barrels)	Total	United States	Canada	Other
Proved developed and undeveloped crude oil reserves:
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	275.1	225.2	37.7	12.2
Revisions of previous estimates	20.2	18.2	1.8	0.2

Extensions and discoveries	5.7	3.4	2.3	—
Purchases of properties	3.5	3.5	–	–
Sales of properties	(1.8)	(1.8)	—	–
Production	(34.0)	(30.3)	(3.6)	(0.1)
December 31, 2025 ¹	268.7	218.2	38.2	12.3
Proved developed crude oil reserves:
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	184.7	164.1	20.4	0.2
December 31, 2025 ²	173.1	150.8	22.1	0.2
Proved undeveloped crude oil reserves:
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	90.4	61.1	17.3	12.0
December 31, 2025 ³	95.6	67.4	16.1	12.1

1 Total and United States includes proved reserves of 13.9 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 12.1 MMBBL attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 1.8 MMBBL attributable to the noncontrolling interest in MP GOM.

2025 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The crude oil reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices.

Extensions and discoveries - In 2025, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and in the Kaybob Duvernay in Canada.

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 the 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 the 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.


(Millions of barrels)	Total	United States	Canada	Other
Proved developed and undeveloped NGL reserves:
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	38.6	34.1	4.5	—
Revisions of previous estimates	1.4	1.2	0.2	—

Extensions and discoveries	1.1	0.7	0.4	—
Purchases of properties	0.4	0.4	–	—
Sale of properties	(0.8)	(0.8)	—	—
Production	(4.0)	(3.8)	(0.2)	—
December 31, 2025 ¹	36.7	31.8	4.9	—
Proved developed NGL reserves:
December 31, 2022	29.7	27.4	2.3	—
December 31, 2023	25.9	24.1	1.8	—
December 31, 2024	24.1	21.9	2.2	—
December 31, 2025 ²	21.7	19.2	2.5	—
Proved undeveloped NGL reserves:
December 31, 2022	12.0	10.2	1.8	—
December 31, 2023	11.7	10.2	1.5	—
December 31, 2024	14.5	12.2	2.3	—
December 31, 2025	15.0	12.6	2.4	—

1 Total and United States includes total proved reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.

2025 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates - The NGL reserves revisions in 2025 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America, partially offset by lower commodity prices in the United States.

Extensions and discoveries - In 2025, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

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 the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the 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 the Tupper Montney and the 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.


(Billions of cubic feet)	Total	United States	Canada	Other
Proved developed and undeveloped natural gas reserves:
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	2,491.8	288.9	2,199.9	3.0
Revisions of previous estimates	26.7	(8.7)	30.8	4.6

Extensions and discoveries	217.2	4.7	212.5	—
Purchases of properties	2.4	2.4	—	—
Sale of properties	(5.1)	(5.1)	—	—
Production	(185.3)	(31.0)	(154.3)	—
December 31, 2025 1,2	2,547.7	251.2	2,288.9	7.6
Proved developed natural gas reserves:
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	1,364.2	196.8	1,167.2	0.2
December 31, 2025 2,3	1,345.1	166.4	1,178.5	0.2
Proved undeveloped natural gas reserves:
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	1,127.6	92.1	1,032.7	2.8
December 31, 2025 4	1,202.6	84.8	1,110.4	7.4

1 Total and United States includes total proved reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM.

2 Includes proved natural gas reserves to be consumed in operations as fuel of 54.2 BCF, 35.1 BCF and 7.4 BCF for the U.S., Canada and Other, respectively, with 1.7 BCF attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved developed reserves of 3.9 BCF attributable to the noncontrolling interest in MP GOM.

4 Total and United States includes proved undeveloped reserves of 0.3 BCF attributable to the noncontrolling interest in MP GOM.

2025 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The natural gas reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney, partially offset by negative revisions due to increased royalty rates and accelerated royalty incentive payouts resulting from higher commodity prices in the Tupper Montney and the effects of reduced oil price in the Eagle Ford Shale.

Extensions and discoveries - In 2025, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

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 the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the 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 the Tupper Montney and the 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 the Tupper Montney and the 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 the Tupper Montney.

Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in the 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.


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2025
Property acquisition costs
Unproved	$	5.5	$	—	$	—	$	5.5
Proved	23.6		—		—		23.6
Total acquisition costs	29.1		—		—		29.1
Exploration costs	71.6		0.3		144.3		216.2
Development costs	696.2		152.5		102.9		951.6
Total costs incurred	796.9		152.8		247.2		1,196.9
Charged to expense
Dry hole expense	(0.9)		—		31.0		30.1
Geophysical and other costs	34.3		0.3		35.3		69.9
Total charged to expense 1	33.4		0.3		66.3		100.0
Property additions	$	763.5	$	152.5	$	180.9	$	1,096.9
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 1	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 1	166.5		0.4		57.0		223.9
Property additions	$	671.3	$	206.2	$	13.1	$	890.6

1 Excludes undeveloped lease amortization for the years ended 2025, 2024 and 2023 of $11.7 million, $9.6 million and $10.9 million, respectively.


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2025
Revenues
Crude oil and natural gas liquids sales	$	2,047.4	$	254.4	$	5.7	$	2,307.5
Natural gas sales	106.5		275.8		—		382.3

Total oil and natural gas revenues	2,153.9		530.2		5.7		2,689.8
Other operating revenues	5.9		1.7		10.0		17.6
Total revenues	2,159.8		531.9		15.7		2,707.4
Costs and expenses
Lease operating expenses	577.1		185.6		2.5		765.2
Severance and ad valorem taxes	37.7		1.5		—		39.2
Transportation, gathering and processing	107.0		92.7		—		199.7


Exploration costs charged to expense	33.5		0.3		66.2		100.0
Undeveloped lease amortization	7.5		0.1		4.1		11.7
Depreciation, depletion and amortization	822.1		144.8		2.5		969.4
Accretion of asset retirement obligations	46.6		10.3		0.7		57.6
Impairment of assets	115.0		—		—		115.0
Selling and general expenses	13.7		23.7		8.8		46.2
Other expenses (benefits)	13.4		3.5		(0.4)		16.5
Total costs and expenses	1,773.6		462.5		84.4		2,320.5
Results of operations before taxes	386.2		69.4		(68.7)		386.9
Income tax expense (benefit)	77.7		14.6		(2.1)		90.2
Results of operations	$	308.5	$	54.8	$	(66.6)	$	296.7
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

1 Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM.


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2023
Revenues
Crude oil and natural gas liquids sales	$	2,829.1	$	165.7	$	11.0	$	3,005.8
Natural gas sales	92.7		278.2		—		370.9
Sales of purchased natural gas	—		72.2		—		72.2
Total oil and natural gas revenues	2,921.8		516.1		11.0		3,448.9
Other operating revenues	6.5		1.4		—		7.9
Total revenues	2,928.3		517.5		11.0		3,456.8
Costs and expenses
Lease operating expenses	630.7		151.8		1.9		784.4
Severance and ad valorem taxes	41.4		1.4		—		42.8
Transportation, gathering and processing	157.0		76.0		—		233.0
Costs of purchased natural gas	—		51.7		—		51.7
Exploration costs charged to expense	166.5		0.4		57.0		223.9
Undeveloped lease amortization	8.1		0.1		2.7		10.9
Depreciation, depletion and amortization	706.0		142.2		2.3		850.5
Accretion of asset retirement obligations	37.8		7.8		0.4		46.0


Selling and general expenses	11.8		16.5		9.4		37.7
Other expenses	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 amounts attributable to the noncontrolling interest in MP GOM.


(Millions of dollars)	United States		Canada		Other		Total
December 31, 2025
Future cash inflows	$	15,502.7	$	6,850.9	$	873.7	$	23,227.3
Future development costs	(1,969.6)		(812.6)		(204.0)		(2,986.2)
Future production costs	(6,707.7)		(4,240.9)		(343.4)		(11,292.0)
Future income taxes	(602.4)		(342.8)		(176.2)		(1,121.4)
Future net cash flows	6,223.0		1,454.6		150.1		7,827.7
10% annual discount for estimated timing of cash flows	(2,459.4)		(625.4)		(118.7)		(3,203.5)
Standardized measure of discounted future net cash flows	$	3,763.6	$	829.2	$	31.4	$	4,624.2
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

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.


(Millions of dollars)	2025		2024		2023
Net changes in prices and production costs 2	$	(1,126.6)	$	(1,116.5)	$	(5,845.6)
Net changes in development costs	46.4		(152.7)		(78.8)
Sales and transfers of oil and natural gas produced, net of production costs	(1,685.7)		(1,824.8)		(2,264.8)
Net change due to extensions and discoveries	122.0		583.7		770.4
Net change due to purchases and sales of proved reserves	62.6		—		(96.1)
Development costs incurred	686.2		668.6		703.7
Accretion of discount	598.3		773.5		1,393.3
Revisions of previous quantity estimates	403.9		(688.1)		(771.5)
Net change in income taxes	121.2		298.8		1,229.6
Net (decrease) increase	(771.7)		(1,457.5)		(4,959.8)
Standardized measure at January 1	5,395.9		6,853.4		11,813.2
Standardized measure at December 31	$	4,624.2	$	5,395.9	$	6,853.4

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

2 The average prices used for crude oil (WTI) were $65.34/BBL in 2025, $75.48/BBL in 2024 and $78.22/BBL in 2023. The average prices used for natural gas (Henry Hub) were $3.39/MCF in 2025, $2.13/MCF in 2024 and $2.64/MCF in 2023.


(Millions of dollars)	United States		Canada		Other		Total
December 31, 2025
Unproved oil and natural gas properties 1	$	207.0	$	6.4	$	16.3	$	229.7
Proved oil and natural gas properties	17,417.6		4,865.4		439.1		22,722.1
Gross capitalized costs	17,624.6		4,871.8		455.4		22,951.8
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(118.5)		—		(11.5)		(130.0)
Proved oil and natural gas properties	(11,275.7)		(3,412.0)		(47.0)		(14,734.7)
Net capitalized costs	$	6,230.4	$	1,459.8	$	396.9	$	8,087.1
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

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.

Significant Accounting Polices (Policies)	12 Months Ended
Significant Accounting Polices (Policies)	Dec. 31, 2025
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 oil and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties, in which Murphy shares in the undivided interest with other producers, are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The Company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2025 and 2024, 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, 2025 and 2024, 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. 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. 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.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	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 the criteria of 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”, “Transportation, gathering and processing”, “Exploration expenses”, “Other operating 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 Statements 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 the 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 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. Certain physical delivery sale and purchase contracts are entered into in the normal course of business and qualify for, and are designated under, the normal purchase and normal sale scope exception provided by ASC 815, “Derivatives and Hedging”. Accordingly, these contracts are not accounted for as derivative instruments or recorded at fair value in the Consolidated Balance Sheets. Revenues and expenses associated with these contracts are recognized in net income (loss) when the underlying physical transactions occur. 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 or three years. The Company estimates the number of stock options and PSUs that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense, when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (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.
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 Statements 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 Income Tax Disclosures. In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The 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. The Company adopted this standard in the fourth quarter of 2025. The adoption did not affect the calculation of income tax expense. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note H. 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 are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impacts on our results of operations, cash flows and financial condition. The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.

Other Financial Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Other Financial Information [Abstract]
Net gains (loss) from foreign currency transactions	$ (29.4)	$ 45.4	$ (10.8)

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, 2025 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	$ (148,280)
Prior service (credit) cost	(16,320)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(164,600)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	18,862
Prior service (credit) cost	2,873
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 21,735

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

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, 2025 USD ($) $ / bbl	Dec. 31, 2024 USD ($) $ / bbl	Dec. 31, 2023 USD ($) $ / bbl
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]
Net changes in prices and production costs	$ (1,126.6)	$ (1,116.5)	$ (5,845.6)
Net changes in development costs	46.4	(152.7)	(78.8)
Sales and transfers of oil and natural gas produced, net of production costs	(1,685.7)	(1,824.8)	(2,264.8)
Net change due to extensions and discoveries	122.0	583.7	770.4
Net change due to purchases and sales of proved reserves	62.6	0.0	(96.1)
Development costs incurred	686.2	668.6	703.7
Accretion of discount	598.3	773.5	1,393.3
Revisions of previous quantity estimates	403.9	(688.1)	(771.5)
Net change in income taxes	121.2	298.8	1,229.6
Net (decrease) increase	(771.7)	(1,457.5)	(4,959.8)
Standardized measure, beginning balance	5,395.9	6,853.4	11,813.2
Standardized measure, ending balance	$ 4,624.2	$ 5,395.9	$ 6,853.4
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	65.34	75.48	78.22
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	3.39	2.13	2.64

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues and other income
Total revenue from sales to customers	$ 2,689,845,000	$ 3,018,598,000	$ 3,448,854,000
Gain (loss) on derivative instruments	5,927,000	(1,707,000)	0
Gain on sale of assets and other operating income	23,051,000	11,583,000	11,293,000
Total revenues and other income	2,718,823,000	3,028,474,000	3,460,147,000
Costs and expenses
Lease operating expenses	765,240,000	936,960,000	784,391,000
Severance and ad valorem taxes	39,238,000	39,162,000	42,787,000
Transportation, gathering and processing	199,693,000	210,827,000	232,985,000
Costs of purchased natural gas	0	3,147,000	51,682,000
Exploration expenses, including undeveloped lease amortization	111,670,000	133,538,000	234,776,000
Selling and general expenses	137,332,000	110,085,000	117,306,000
Depreciation, depletion and amortization	977,753,000	865,753,000	861,602,000
Accretion of asset retirement obligations	57,730,000	52,511,000	46,059,000
Impairment of assets	115,002,000	62,909,000	0
Other operating expense	13,928,000	10,989,000	46,530,000
Total costs and expenses	2,417,586,000	2,425,881,000	2,418,118,000
Operating income from continuing operations	301,237,000	602,593,000	1,042,029,000
Other income (loss)
Other income (loss)	(22,299,000)	70,902,000	(8,587,000)
Interest expense, net	(96,072,000)	(105,926,000)	(112,373,000)
Total other loss	(118,371,000)	(35,024,000)	(120,960,000)
Income from continuing operations before income taxes	182,866,000	567,569,000	921,069,000
Income tax expense	44,552,000	78,272,000	195,921,000
Income from continuing operations	138,314,000	489,297,000	725,148,000
Income (loss) from discontinued operations, net of income taxes	485,000	(2,812,000)	(1,467,000)
Net income including noncontrolling interest	138,799,000	486,485,000	723,681,000
Less: Net income attributable to noncontrolling interest	34,565,000	79,314,000	62,122,000
NET INCOME ATTRIBUTABLE TO MURPHY	$ 104,234,000	$ 407,171,000	$ 661,559,000
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations (in USD per share)	$ 0.73	$ 2.73	$ 4.27
Discontinued operations (in USD per share)	0	(0.02)	(0.01)
Net income (in USD per share)	0.73	2.71	4.26
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations (in USD per share)	0.72	2.72	4.23
Discontinued operations (in USD per share)	0	(0.02)	(0.01)
Net income (in USD per share)	0.72	2.70	4.22
Cash dividends per Common share (in USD per share)	$ 1.300	$ 1.200	$ 1.100
Average common shares outstanding (thousands)
Basic (in shares)	143,124,118	150,011,458	155,233,560
Diluted (in shares)	144,025,322	151,027,352	156,646,429
Revenue from production
Revenues and other income
Total revenue from sales to customers	$ 2,689,845,000	$ 3,014,856,000	$ 3,376,639,000
Sales of purchased natural gas
Revenues and other income
Total revenue from sales to customers	$ 0	$ 3,742,000	$ 72,215,000

Subsequent Event	12 Months Ended
Subsequent Event	Dec. 31, 2025
Subsequent Events [Abstract]
Subsequent Event	Note U – Subsequent Event On January 28, 2026, the Board of Directors of Murphy Oil Corporation (NYSE: MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $0.35 per share, which on an annualized basis would be $1.40 per share. The dividend is payable on March 2, 2026, to stockholders of record as of February 17, 2026. In January 2026, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In particular, the Company closed a public offering of $500.0 million aggregate principal amount of its 2034 Notes, used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. In addition, the Company entered into an amendment to its credit agreement which increased its RCF capacity from $1.35 billion to $2.0 billion and extended the term of the agreement to 2031. See Note F for additional information on these transactions. Subsequent to the balance sheet date, the Company announced oil discoveries at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and dry holes at the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire. A portion of the Civette-1X dry hole charge was recorded in 2025. The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026. See Note D for additional information.

Employee and Retiree Benefit Plans - Schedule of Components of Net Periodic Benefit Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7,094	$ 7,042	$ 6,542
Interest cost	33,798	33,554	34,140
Expected return on plan assets	(35,511)	(33,427)	(32,839)
Amortization of prior service cost (credit)	1,967	2,316	620
Recognized actuarial (gain) loss	7,262	9,438	9,776
Net periodic benefit cost (credit)	14,610	18,923	18,239
Other pension costs	276	251	219
Total net periodic benefit cost (credit)	14,886	19,174	18,458
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	382	436	495
Interest cost	3,261	2,923	3,241
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	(532)	(532)	(532)
Recognized actuarial (gain) loss	(3,182)	(3,586)	(3,512)
Net periodic benefit cost (credit)	(71)	(759)	(308)
Other pension costs	0	0	0
Total net periodic benefit cost (credit)	$ (71)	$ (759)	$ (308)

Income Taxes

12 Months Ended

Dec. 31, 2025

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)	2025		2024		2023
Income (loss) from continuing operations before income taxes
United States	$	195,245	$	468,202	$	901,761
Foreign	(12,379)		99,367		19,308
Total	$	182,866	$	567,569	$	921,069
Income tax expense
Current tax expense

U.S. State and Local	$	468	$	1,153	$	2,916
Foreign	9,411		4,685		13,182
Total current tax expense	9,879		5,838		16,098
Deferred tax expense
U.S. Federal	37,825		55,377		170,115
U.S. State and Local	(1,214)		(5,641)		3,706
Foreign	(1,938)		22,698		6,002
Total deferred tax expense	34,673		72,434		179,823
Total income tax expense
U.S. Federal	37,825		55,377		170,115
U.S. State and Local	(746)		(4,488)		6,622
Foreign	7,473		27,383		19,184
Total income tax expense	$	44,552	$	78,272	$	195,921

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)	2025				2024				2023
	Amount		Percent		Amount		Percent		Amount		Percent
Income tax expense based on the U.S. statutory tax rate	$	38,402	21.0	%	$	119,190	21.0	%	$	193,424	21.0	%
Domestic Federal
Tax Credits
Research and development tax credits	2,521		1.4		(6,841)		(1.2)		(8,805)		(1.0)
Nontaxable or Nondeductible Items
Tax effect on income attributable to NCI	(7,259)		(4.0)		(16,656)		(2.9)		(13,046)		(1.4)
U.S. tax benefit on certain foreign upstream investments	—		—		(33,677)		(5.9)		—		—
Other	(397)		(0.2)		2,398		0.4		(293)		—

Share-based payment awards	5,595		3.1		2,340		0.4		2,636		0.3

State and Local Income Taxes, Net of Federal Income Tax Effect 1	(589)		(0.3)		(3,546)		(0.6)		4,725		0.5
Foreign Tax Effects
Canada
Statutory tax rate differential	2,629		1.4		5,428		1.0		3,732		0.4
Research and development tax credits	(3,875)		(2.1)		(3,547)		(0.6)		(3,982)		(0.4)



Other Foreign jurisdictions
Statutory tax rate differential	4,960		2.7		9,127		1.6		2,844		0.3
Changes in valuation allowances
Côte d’Ivoire	13,140		7.2		—		—		—		—

Other Foreign Jurisdictions	(2,922)		(1.6)		2,636		0.5		10,853		1.2
Other	(5,825)		(3.2)		(532)		(0.2)		1,377		0.1
Worldwide Changes in Unrecognized Tax Benefits	(1,828)		(1.0)		1,952		0.3		2,456		0.3
Effective Tax Rate	$	44,552	24.4	%	$	78,272	13.8	%	$	195,921	21.3	%

1 State taxes primarily include Texas and Louisiana.

The following table displays cash taxes paid, net of refunds, for each of the three years presented.


(Thousands of dollars)	2025		2024		2023

U.S. State and Local
Alabama	$	(1,868)	$	—	$	4,838
Texas	1,500		2,300		1,079
Other	50		—		51
Total U.S. State and Local	(318)		2,300		5,968
Foreign
Canada	2,929		6,480		3,553
Canada - Alberta	2,809		3,269		1,756
Brunei	681		599		1,079

Total Foreign	6,419		10,348		6,388
Total	$	6,101	$	12,648	$	12,356

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)	2025		2024
Deferred tax assets
Property and leasehold costs	$	235,509	$	225,379
Liabilities for dismantlements	40,242		36,719
Postretirement and other employee benefits	66,418		66,293

U. S. net operating loss	224,956		289,594
Investment in partnership	20,307		9,096
Other deferred tax assets 1	97,660		100,352
Total gross deferred tax assets	685,092		727,433
Less: Valuation allowance	(157,807)		(149,498)
Net deferred tax assets	527,285		577,935
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)		(5,000)
Accumulated depreciation, depletion and amortization	(812,727)		(811,178)

Other deferred tax liabilities 1	(87,895)		(97,547)
Total gross deferred tax liabilities	(905,622)		(913,725)
Net deferred tax (liabilities) assets	$	(378,337)	$	(335,790)

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 $8.3 million in 2025, 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 $1.1 billion at year-end 2025 with a corresponding deferred tax asset of $225.0 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 2037.

Other Information

Currently, the Company considers $100.0 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $5.0 million liability. At December 31, 2025, $1.6 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)	2025		2024		2023
Balance at January 1	$	9,979	$	6,384	$	3,928
Additions for tax positions related to current year	—		1,643		—
Additions for tax positions related to prior year	—		1,952		2,456
Reductions for tax positions related to prior year	(882)		—		—

Settlements with taxing authorities	(946)		—		—

Balance at December 31	$	8,151	$	9,979	$	6,384

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, 2025, 2024 and 2023, 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 2026, 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 Statements of Operations during 2026.

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, 2025, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2016; Canada – 2021; and Malaysia – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477617/942-740-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12C

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/740/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-21

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-17

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

+ Details

Business Segments - Schedule of Revenue by Major Customers (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Chevron Corporation
Segment Reporting Information [Line Items]
Concentration risk	19.00%	13.00%	16.00%
ExxonMobil Corporation
Segment Reporting Information [Line Items]
Concentration risk	12.00%	20.00%	27.00%
Phillips 66
Segment Reporting Information [Line Items]
Concentration risk		10.00%

- Definition

For an entity that discloses a concentration risk in relation to quantitative amount, which serves as the "benchmark" (or denominator) in the equation, this concept represents the concentration percentage derived from the division.

+ References + Details

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, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income (loss) from continuing operations before income taxes
United States									$ 195,245	$ 468,202	$ 901,761
Foreign									(12,379)	99,367	19,308
Income from continuing operations before income taxes	$ 28,900	$ (3,700)	$ 34,900	$ 122,800	$ 78,600	$ 153,800	$ 189,600	$ 145,600	182,866	567,569	921,069
Current tax expense
U.S. State and Local									468	1,153	2,916
Foreign									9,411	4,685	13,182
Total current tax expense									9,879	5,838	16,098
Deferred tax expense
U.S. Federal									37,825	55,377	170,115
U.S. State and Local									(1,214)	(5,641)	3,706
Foreign									(1,938)	22,698	6,002
Total deferred tax expense									34,673	72,434	179,823
U.S. Federal									37,825	55,377	170,115
U.S. State and Local									(746)	(4,488)	6,622
Foreign									7,473	27,383	19,184
Total income tax expense									$ 44,552	$ 78,272	$ 195,921

Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2025

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 Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments			Total
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	(134,692)		27,737			(106,955)
Balance at December 31, 2024	(516,324)		(111,748)			(628,072)
2025 components of other comprehensive income (loss):
Before reclassifications to income	73,993		(3,633)			70,360
Reclassifications to income	—		3,485		¹	3,485
Net other comprehensive income (loss)	73,993		(148)			73,845
Balance at December 31, 2025	$	(442,331)	$	(111,896)		$	(554,227)

1 Reclassifications before taxes of $4.2 million and $5.4 million are included in the computation of net periodic benefit expense in 2025 and 2024, respectively. See Note J for additional information. Related income taxes of $0.7 million and $1.4 million are included in income tax expense in 2025 and 2024, respectively.

Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2025

Other Financial Information [Abstract]

Schedule of Noncash Operating Working Capital (Increase) Decrease

Supplemental Information to Statements of Cash Flows


(Thousands of dollars)	2025		2024		2023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(75,437)	$	71,081	$	47,151
(Increase) decrease in inventories	(1,461)		1,327		329
(Increase) decrease in prepaid expenses	539		1,192		(1,293)
Increase (decrease) in accounts payable and accrued liabilities 1	3,101		3,287		(140,011)
Increase (decrease) in income taxes payable	(794)		(2,004)		(5,537)
Net (increase) decrease in noncash working capital	$	(74,052)	$	74,883	$	(99,361)

Supplementary disclosures:

Interest paid, net of amounts capitalized of $8.8 million in 2025, $11.4 million in 2024 and $14.5 million in 2023	88,119		78,806		108,912

Non-cash investing activities:
Asset retirement costs capitalized	$	9,629	$	47,233	$	32,975
(Increase) decrease in capital expenditure accrual	(98,778)		(5,935)		17,517

1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments.

Common Stock Issued and Outstanding - Schedule of Number of Shares of Common Stock Issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning of year (in shares)	145,845,124	152,748,642	155,467,319
Stock options exercised (in shares)			11,000
Restricted stock awards (in shares)	553,478	1,105,268	689,824
Treasury shares purchased (in shares)	(3,613,450)	(8,008,786)	(3,411,158)
End of year (in shares)	142,785,152	145,845,124	152,748,642
Withholdings for Statutory Income Taxes Owed
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock options exercised (in shares)	0	0	2,657

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Current assets
Cash and cash equivalents	$ 377,196	$ 423,569
Accounts receivable, net	346,759	272,530
Inventories	57,284	54,858
Prepaid expenses	35,473	34,322
Total current assets	816,712	785,279
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $15,068,149 in 2025 and $13,811,539 in 2024	8,136,346	8,054,653
Operating lease assets	805,464	777,536
Deferred charges and other assets	74,104	50,011
Total assets	9,832,626	9,667,479
Current liabilities
Current maturities of long-term debt, finance lease	2,514	871
Accounts payable	572,183	472,165
Income taxes payable	18,209	19,003
Other taxes payable	28,295	31,685
Operating lease liabilities	278,834	253,208
Other accrued liabilities	120,755	117,802
Current asset retirement obligations	41,959	48,080
Total current liabilities	1,062,749	942,814
Long-term debt, including finance lease obligation	1,382,566	1,274,502
Asset retirement obligations	970,908	960,804
Deferred credits and other liabilities	263,596	274,345
Non-current operating lease liabilities	537,773	537,381
Deferred income taxes	378,337	335,790
Total liabilities	4,595,929	4,325,636
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 at December 31, 2025 and 195,100,628 shares at December 31, 2024	195,101	195,101
Capital in excess of par value	859,633	848,950
Retained earnings	6,691,318	6,773,289
Accumulated other comprehensive loss	(554,227)	(628,072)
Treasury stock	(2,073,445)	(1,995,018)
Murphy Shareholders' Equity	5,118,380	5,194,250
Noncontrolling interest	118,317	147,593
Total equity	5,236,697	5,341,843
Total liabilities and equity	$ 9,832,626	$ 9,667,479

Incentive Plans

12 Months Ended

Dec. 31, 2025

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.

In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan). All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan. Additional information on the 2025 Long-Term Plan can be found in the Company’s Definitive Proxy Statement (Definitive 14A) dated March 28, 2025.

The Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2020 Long-Term Plan, and the 2025 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 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock to employees. These grants may be in the form of stock options (nonqualified or incentive), Stock Appreciation Rights (SARs), restricted stock, RSUs, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term. 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, 3.872 million shares are available for grant under the 2025 Long-Term Plan at December 31, 2025.

The Company also has a stock plan that permits the issuance of RSUs, stock options, or a combination thereof, to non-employee directors (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)	2025		2024		2023
Compensation charged against income before income tax benefit	$	50,107	$	40,831	$	58,760
Related income tax benefit recognized in income	6,438		5,513		9,330

As of December 31, 2025, there were $46.5 million in compensation costs, to be expensed over approximately the next two years, related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable withholding obligations, upon each RSU vest.

Equity-Settled Awards

PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023, 2024 and February 2025 under the 2020 Long-Term Plan, and in August 2025 under the 2025 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 2025, 2024 and 2023 are presented in the following table.


	2025	2024	2023
Fair value per share at grant date	$19.65 - $22.11	$41.95	$60.46
Assumptions
Expected volatility	40.00%	50.00%	81.00%
Risk-free interest rate	4.25%	4.14%	3.90%
Stock beta	0.980	1.062	1.034
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)	2025	2024	2023
Outstanding at beginning of year	1,392,421	1,818,188	2,148,467
Granted	657,730	536,900	409,160
Vested and issued	(481,670)	(938,599)	(408,135)
Forfeited	(104,966)	(24,068)	(331,304)
Outstanding at end of year	1,463,515	1,392,421	1,818,188

TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s non-employee directors under the 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan and 2025 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	2025	2024	2023
Non-Employee Directors 1	Closing Stock Price at Grant Date	$22.50 - $31.25	$30.26 - $45.70	$43.27
Long-Term Incentive Plan 2	Average High/Low Stock Price at Grant Date	$23.09 - $25.98	$37.78 - $45.98	$42.20

1 Under the 2021 NED Plan, RSUs granted in 2025 are scheduled to vest in February 2026.

2 The RSUs granted under the 2020 Long-Term Plan and the 2025 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)	2025	2024	2023
Outstanding at beginning of year	1,558,600	1,219,584	1,227,792
Granted	559,284	741,228	556,100
Vested and issued	(360,281)	(330,444)	(517,047)
Forfeited	(95,951)	(71,768)	(47,261)
Outstanding at end of year	1,661,652	1,558,600	1,219,584

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, 2024, there were no outstanding SARs or stock options.

During 2023, 11,000 stock options were exercised, and 2,000 stock options were forfeited, both at an exercise price of $28.51 per share, leaving zero options outstanding as of December 31, 2023.

Cash-Settled Awards

The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of CRSUs.

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 $7.5 million in 2025, $1.7 million in 2024 and $29.4 million in 2023.

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 $37.8 million, $37.1 million and $30.9 million was recorded in 2025, 2024 and 2023, respectively, for these plans.

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, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	$ 23,227.3	$ 25,435.4	$ 27,944.5
Future development costs	(2,986.2)	(3,103.3)	(2,759.2)
Future production costs	(11,292.0)	(12,013.9)	(12,368.5)
Future income taxes	(1,121.4)	(1,348.1)	(1,813.4)
Future net cash flows	7,827.7	8,970.1	11,003.4
10% annual discount for estimated timing of cash flows	(3,203.5)	(3,574.2)	(4,150.0)
Standardized measure of discounted future net cash flows	4,624.2	5,395.9	6,853.4	$ 11,813.2
United States
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	15,502.7	18,118.1	18,927.6
Future development costs	(1,969.6)	(2,024.9)	(1,685.3)
Future production costs	(6,707.7)	(7,645.7)	(7,856.2)
Future income taxes	(602.4)	(893.5)	(1,057.5)
Future net cash flows	6,223.0	7,554.0	8,328.6
10% annual discount for estimated timing of cash flows	(2,459.4)	(2,887.3)	(2,840.6)
Standardized measure of discounted future net cash flows	3,763.6	4,666.7	5,488.0
Canada
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	6,850.9	6,304.4	8,012.7
Future development costs	(812.6)	(825.9)	(769.6)
Future production costs	(4,240.9)	(4,026.5)	(4,223.6)
Future income taxes	(342.8)	(251.2)	(634.6)
Future net cash flows	1,454.6	1,200.8	2,384.9
10% annual discount for estimated timing of cash flows	(625.4)	(486.0)	(1,056.9)
Standardized measure of discounted future net cash flows	829.2	714.8	1,328.0
Other
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	873.7	1,012.9	1,004.2
Future development costs	(204.0)	(252.5)	(304.3)
Future production costs	(343.4)	(341.7)	(288.7)
Future income taxes	(176.2)	(203.4)	(121.3)
Future net cash flows	150.1	215.3	289.9
10% annual discount for estimated timing of cash flows	(118.7)	(200.9)	(252.5)
Standardized measure of discounted future net cash flows	$ 31.4	$ 14.4	$ 37.4

Common Stock Issued and Outstanding

12 Months Ended

Dec. 31, 2025

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)	2025	2024	2023
Beginning of year	145,845,124	152,748,642	155,467,319
Stock options exercised 1	—	—	2,657
Restricted stock awards 1	553,478	1,105,268	689,824

Treasury shares purchased	(3,613,450)	(8,008,786)	(3,411,158)
End of year	142,785,152	145,845,124	152,748,642

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, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.8 million including excise taxes and fees). As of December 31, 2025, the Company had $550.1 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.

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2025

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 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)	2025		2024		2023
Net crude oil and condensate revenue
United States - Onshore	$	617,358	$	586,584	$	676,139
United States - Offshore 1	1,355,527		1,777,723		2,072,353
Canada - Onshore	61,715		70,855		78,088
Canada - Offshore	187,030		193,961		78,650
Other	5,713		6,537		11,022
Total crude oil and condensate revenue	2,227,343		2,635,660		2,916,252
Net natural gas liquids revenue
United States - Onshore	41,518		32,853		33,178
United States - Offshore 1	33,029		38,858		47,434
Canada - Onshore	5,626		7,454		8,914
Total natural gas liquids revenue	80,173		79,165		89,526
Net natural gas revenue
United States - Onshore	35,524		17,443		21,346
United States - Offshore 1	70,968		50,329		71,332
Canada - Onshore	275,837		232,259		278,183
Total natural gas revenue	382,329		300,031		370,861
Revenue from production	2,689,845		3,014,856		3,376,639
Sales of purchased natural gas 2

Canada - Onshore	—		3,742		72,215
Total sales of purchased natural gas	—		3,742		72,215
Total revenue from sales to customers	2,689,845		3,018,598		3,448,854
Gain (loss) on derivative instruments	5,927		(1,707)		—
Gain on sale of assets and other operating income	23,051		11,583		11,293
Total revenues and other income	$	2,718,823	$	3,028,474	$	3,460,147

1 Includes revenue attributable to the 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, 2025 and 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $165.3 million and $178.3 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, 2025, 2024 or 2023.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

Performance 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, 2025, 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.

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Natural Gas and NGLs

Q2 2030

Deliveries from dedicated acreage in Eagle Ford Shale

As produced

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at USD index pricing

30 MMCF/D

Canada

Natural Gas

Q4 2028

Contracts to sell natural gas at USD index pricing

10 MMCF/D

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at CAD fixed pricing

50 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at CAD fixed pricing

9 MMCF/D

Canada

NGLs

Q4 2026

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.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
-Paragraph 7
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/606/tableOfContent

+ Details

Employee and Retiree Benefit Plans - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2025 USD ($) investment	Dec. 31, 2024 USD ($)	Dec. 31, 2023 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	7.90%
Ultimate rate of health care cost	4.00%
Weighted average expected return on plan asset	7.30%
Basis used to determine expected return on plan asset, average expected investment expenses	0.50%
Perentage return on plan assets over the last ten years	4.10%
Number of investments in hedge funds and other alternative investments (in investments) \| investment	4
Defined benefit plan, percentage of employer's matching contribution	6.00%
Thrift plan expense	$ 9,100	$ 8,700	$ 8,500
Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	7.60%
Equity securities \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%
Equity securities \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	75.00%
Fixed income securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	5.00%
Fixed income securities \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	20.00%
Fixed income securities \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%
Other \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%
Other \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15.00%
Cash equivalents \| Minimum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%
Cash equivalents \| Maximum \| Domestic Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	20.00%
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	$ 25,067	$ 35,477
Weighted average expected return on plan asset	7.29%	7.19%
Pension Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 24,300
Contributions to benefit plans, next fiscal year	23,800
Pension Benefits \| Foreign Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans, next fiscal year	800
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 12,928	$ 12,984
Weighted average expected return on plan asset	0.00%	0.00%
Other Postretirement Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 12,900
Contributions to benefit plans, next fiscal year	$ 4,700

Net Income (Loss) Per Common Share

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Net Income (Loss) Per Common Share

Note L – Net Income (Loss) Per Common Share

Net income 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, except per share amounts)	2025		2024		2023
Basic method	143,124,118		150,011,458		155,233,560
Dilutive restricted stock units	901,204		1,015,894		1,412,869
Diluted method	144,025,322		151,027,352		156,646,429
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	0.73	$	2.73	$	4.27
Discontinued operations	—		(0.02)		(0.01)
Net income	$	0.73	$	2.71	$	4.26
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	0.72	$	2.72	$	4.23
Discontinued operations	—		(0.02)		(0.01)
Net income	$	0.72	$	2.70	$	4.22

Revenue from Contracts with Customers - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) segment revenueStream	Dec. 31, 2024 USD ($)
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 \| $	$ 165.3	$ 178.3

Financing Arrangements and Debt

12 Months Ended

Dec. 31, 2025

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)	2025		2024
Notes payable

5.875% notes, due December 2027	$	78,899	$	78,899
6.375% notes, due July 2028	148,590		148,590
7.050% notes, due May 2029	117,582		117,582
6.000% notes, due October 2032	600,000		600,000
5.875% notes, due December 2042 ¹	339,761		339,761

Total notes payable	1,284,832		1,284,832
Unamortized debt issuance cost and discount on notes payable	(12,406)		(14,336)
Total notes payable, net of unamortized discount	1,272,426		1,270,496
Finance lease obligations, due through November 2034	12,654		4,877
Total debt including current maturities	1,285,080		1,275,373
Senior Unsecured Revolving Credit Facility	100,000		—
Current maturities	(2,514)		(871)
Total long-term debt	$	1,382,566	$	1,274,502

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 2026, $78.9 million in 2027, $148.6 million in 2028, $217.6 million in 2029, nil in 2030 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

As of December 31, 2025, the Company had a $1.35 billion senior unsecured guaranteed RCF, with a maturity date of October 7, 2029. At December 31, 2025, the Company had $100.0 million outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduced the borrowing capacity of the RCF. At December 31, 2025, the interest rate in effect on borrowings under the facility was 6.04%. At December 31, 2025, the Company was in compliance with all covenants related to the RCF. On the date the Company achieved certain credit ratings (Investment Grade Ratings Date), certain covenants would have been modified as set forth in the RCF. In addition, prior to Investment Grade Ratings Date, the Company would have been 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 bore 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 was 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 was equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10%. The “Adjusted Daily Simple SOFR Rate” of interest was equal to (a) the Daily Simple SOFR, plus (b) 0.10%. The “Applicable Rate” of interest meant, 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.

Subsequent Event - Revolving Credit Facility

On January 2, 2026, the Company entered into an amended credit agreement governing a $2.00 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. The Amended RCF, which is effective January 2026, extends the borrowing term and increases the borrowing capacity of the previous RCF. All terms of the Amended RCF are substantially similar to the existing credit agreement, with an exception for the following: The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero. 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 $12.3 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 Amended RCF.

Debt Offering

On October 3, 2024, the Company closed the public offering of $600.0 million aggregate principal amount of senior notes that bear interest at a rate of 6.000% per annum and mature on October 1, 2032. The Company incurred transaction costs of $10.1 million on the issuance of these notes. The Company pays interest semi-annually on April 1 and October 1 of each year. 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.

Subsequent Event - Debt Offering

On January 23, 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.500% per annum and mature on February 15, 2034. The Company has incurred transaction costs of $8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes.

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.

Subsequent Event - Debt Extinguishment

On January 23, 2026, the Company redeemed the remaining $78.9 million principal amount outstanding of its 2027 Notes and $148.6 million of its 2028 Notes, for an aggregate $227.5 million. The total cost of the debt extinguishment of $3.5 million consisted of cash costs of $2.5 million and non-cash costs of $1.0 million.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/470/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Section 50
-Paragraph 1C
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1E

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Publisher FASB
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Publisher FASB
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+ Details

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, 2025	Dec. 31, 2024
Deferred tax assets
Property and leasehold costs	$ 235,509	$ 225,379
Liabilities for dismantlements	40,242	36,719
Postretirement and other employee benefits	66,418	66,293
U. S. net operating loss	224,956	289,594
Investment in partnership	20,307	9,096
Other deferred tax assets	97,660	100,352
Total gross deferred tax assets	685,092	727,433
Less: Valuation allowance	(157,807)	(149,498)
Net deferred tax assets	527,285	577,935
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)	(5,000)
Accumulated depreciation, depletion and amortization	(812,727)	(811,178)
Other deferred tax liabilities	(87,895)	(97,547)
Total gross deferred tax liabilities	(905,622)	(913,725)
Net deferred tax (liabilities) assets	$ (378,337)	$ (335,790)

Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Oil and Gas Disclosure [Abstract]

Schedule of Proved Reserves Based on Average Prices


	Equivalents
(Millions of barrels of oil equivalent)	Total	United States	Canada	Other
Proved developed and undeveloped reserves:
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	729.0	307.4	408.9	12.7
Revisions of previous estimates	26.0	18.0	7.1	0.9

Extensions and discoveries	43.0	4.9	38.1	—
Purchases of properties	4.3	4.3	—	—
Sale of properties	(3.4)	(3.4)	—	—
Production	(68.9)	(39.3)	(29.5)	(0.1)
December 31, 2025 ¹	730.0	291.9	424.6	13.5
Proved developed reserves:
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	436.2	218.9	217.1	0.2
December 31, 2025 ²	418.9	197.8	220.9	0.2
Proved undeveloped reserves:
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	292.8	88.5	191.8	12.5
December 31, 2025 ³	311.1	94.1	203.7	13.3

1 Total and United States includes proved reserves of 15.0 MMBOE, consisting of 13.9 MMBBL of oil, 0.4 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 1.9 MMBOE, consisting of 1.8 MMBBL of oil and 0.3 BCF of natural gas attributable to the noncontrolling interest in MP GOM.


(Millions of barrels)	Total	United States	Canada	Other
Proved developed and undeveloped crude oil reserves:
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	275.1	225.2	37.7	12.2
Revisions of previous estimates	20.2	18.2	1.8	0.2

Extensions and discoveries	5.7	3.4	2.3	—
Purchases of properties	3.5	3.5	–	–
Sales of properties	(1.8)	(1.8)	—	–
Production	(34.0)	(30.3)	(3.6)	(0.1)
December 31, 2025 ¹	268.7	218.2	38.2	12.3
Proved developed crude oil reserves:
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	184.7	164.1	20.4	0.2
December 31, 2025 ²	173.1	150.8	22.1	0.2
Proved undeveloped crude oil reserves:
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	90.4	61.1	17.3	12.0
December 31, 2025 ³	95.6	67.4	16.1	12.1

1 Total and United States includes proved reserves of 13.9 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 12.1 MMBBL attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 1.8 MMBBL attributable to the noncontrolling interest in MP GOM.


(Millions of barrels)	Total	United States	Canada	Other
Proved developed and undeveloped NGL reserves:
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	38.6	34.1	4.5	—
Revisions of previous estimates	1.4	1.2	0.2	—

Extensions and discoveries	1.1	0.7	0.4	—
Purchases of properties	0.4	0.4	–	—
Sale of properties	(0.8)	(0.8)	—	—
Production	(4.0)	(3.8)	(0.2)	—
December 31, 2025 ¹	36.7	31.8	4.9	—
Proved developed NGL reserves:
December 31, 2022	29.7	27.4	2.3	—
December 31, 2023	25.9	24.1	1.8	—
December 31, 2024	24.1	21.9	2.2	—
December 31, 2025 ²	21.7	19.2	2.5	—
Proved undeveloped NGL reserves:
December 31, 2022	12.0	10.2	1.8	—
December 31, 2023	11.7	10.2	1.5	—
December 31, 2024	14.5	12.2	2.3	—
December 31, 2025	15.0	12.6	2.4	—

1 Total and United States includes total proved reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.


(Billions of cubic feet)	Total	United States	Canada	Other
Proved developed and undeveloped natural gas reserves:
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	2,491.8	288.9	2,199.9	3.0
Revisions of previous estimates	26.7	(8.7)	30.8	4.6

Extensions and discoveries	217.2	4.7	212.5	—
Purchases of properties	2.4	2.4	—	—
Sale of properties	(5.1)	(5.1)	—	—
Production	(185.3)	(31.0)	(154.3)	—
December 31, 2025 1,2	2,547.7	251.2	2,288.9	7.6
Proved developed natural gas reserves:
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	1,364.2	196.8	1,167.2	0.2
December 31, 2025 2,3	1,345.1	166.4	1,178.5	0.2
Proved undeveloped natural gas reserves:
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	1,127.6	92.1	1,032.7	2.8
December 31, 2025 4	1,202.6	84.8	1,110.4	7.4

1 Total and United States includes total proved reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved developed reserves of 3.9 BCF attributable to the noncontrolling interest in MP GOM.

4 Total and United States includes proved undeveloped reserves of 0.3 BCF attributable to the noncontrolling interest in MP GOM.

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2025
Property acquisition costs
Unproved	$	5.5	$	—	$	—	$	5.5
Proved	23.6		—		—		23.6
Total acquisition costs	29.1		—		—		29.1
Exploration costs	71.6		0.3		144.3		216.2
Development costs	696.2		152.5		102.9		951.6
Total costs incurred	796.9		152.8		247.2		1,196.9
Charged to expense
Dry hole expense	(0.9)		—		31.0		30.1
Geophysical and other costs	34.3		0.3		35.3		69.9
Total charged to expense 1	33.4		0.3		66.3		100.0
Property additions	$	763.5	$	152.5	$	180.9	$	1,096.9
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 1	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 1	166.5		0.4		57.0		223.9
Property additions	$	671.3	$	206.2	$	13.1	$	890.6

1 Excludes undeveloped lease amortization for the years ended 2025, 2024 and 2023 of $11.7 million, $9.6 million and $10.9 million, respectively.

Schedule of Results of Operations for Oil and Gas Producing Activities


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2025
Revenues
Crude oil and natural gas liquids sales	$	2,047.4	$	254.4	$	5.7	$	2,307.5
Natural gas sales	106.5		275.8		—		382.3

Total oil and natural gas revenues	2,153.9		530.2		5.7		2,689.8
Other operating revenues	5.9		1.7		10.0		17.6
Total revenues	2,159.8		531.9		15.7		2,707.4
Costs and expenses
Lease operating expenses	577.1		185.6		2.5		765.2
Severance and ad valorem taxes	37.7		1.5		—		39.2
Transportation, gathering and processing	107.0		92.7		—		199.7


Exploration costs charged to expense	33.5		0.3		66.2		100.0
Undeveloped lease amortization	7.5		0.1		4.1		11.7
Depreciation, depletion and amortization	822.1		144.8		2.5		969.4
Accretion of asset retirement obligations	46.6		10.3		0.7		57.6
Impairment of assets	115.0		—		—		115.0
Selling and general expenses	13.7		23.7		8.8		46.2
Other expenses (benefits)	13.4		3.5		(0.4)		16.5
Total costs and expenses	1,773.6		462.5		84.4		2,320.5
Results of operations before taxes	386.2		69.4		(68.7)		386.9
Income tax expense (benefit)	77.7		14.6		(2.1)		90.2
Results of operations	$	308.5	$	54.8	$	(66.6)	$	296.7
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

1 Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM.


(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2023
Revenues
Crude oil and natural gas liquids sales	$	2,829.1	$	165.7	$	11.0	$	3,005.8
Natural gas sales	92.7		278.2		—		370.9
Sales of purchased natural gas	—		72.2		—		72.2
Total oil and natural gas revenues	2,921.8		516.1		11.0		3,448.9
Other operating revenues	6.5		1.4		—		7.9
Total revenues	2,928.3		517.5		11.0		3,456.8
Costs and expenses
Lease operating expenses	630.7		151.8		1.9		784.4
Severance and ad valorem taxes	41.4		1.4		—		42.8
Transportation, gathering and processing	157.0		76.0		—		233.0
Costs of purchased natural gas	—		51.7		—		51.7
Exploration costs charged to expense	166.5		0.4		57.0		223.9
Undeveloped lease amortization	8.1		0.1		2.7		10.9
Depreciation, depletion and amortization	706.0		142.2		2.3		850.5
Accretion of asset retirement obligations	37.8		7.8		0.4		46.0


Selling and general expenses	11.8		16.5		9.4		37.7
Other expenses	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 amounts attributable to the 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 States		Canada		Other		Total
December 31, 2025
Future cash inflows	$	15,502.7	$	6,850.9	$	873.7	$	23,227.3
Future development costs	(1,969.6)		(812.6)		(204.0)		(2,986.2)
Future production costs	(6,707.7)		(4,240.9)		(343.4)		(11,292.0)
Future income taxes	(602.4)		(342.8)		(176.2)		(1,121.4)
Future net cash flows	6,223.0		1,454.6		150.1		7,827.7
10% annual discount for estimated timing of cash flows	(2,459.4)		(625.4)		(118.7)		(3,203.5)
Standardized measure of discounted future net cash flows	$	3,763.6	$	829.2	$	31.4	$	4,624.2
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

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

Schedule of Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows

The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.


(Millions of dollars)	2025		2024		2023
Net changes in prices and production costs 2	$	(1,126.6)	$	(1,116.5)	$	(5,845.6)
Net changes in development costs	46.4		(152.7)		(78.8)
Sales and transfers of oil and natural gas produced, net of production costs	(1,685.7)		(1,824.8)		(2,264.8)
Net change due to extensions and discoveries	122.0		583.7		770.4
Net change due to purchases and sales of proved reserves	62.6		—		(96.1)
Development costs incurred	686.2		668.6		703.7
Accretion of discount	598.3		773.5		1,393.3
Revisions of previous quantity estimates	403.9		(688.1)		(771.5)
Net change in income taxes	121.2		298.8		1,229.6
Net (decrease) increase	(771.7)		(1,457.5)		(4,959.8)
Standardized measure at January 1	5,395.9		6,853.4		11,813.2
Standardized measure at December 31	$	4,624.2	$	5,395.9	$	6,853.4

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities


(Millions of dollars)	United States		Canada		Other		Total
December 31, 2025
Unproved oil and natural gas properties 1	$	207.0	$	6.4	$	16.3	$	229.7
Proved oil and natural gas properties	17,417.6		4,865.4		439.1		22,722.1
Gross capitalized costs	17,624.6		4,871.8		455.4		22,951.8
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(118.5)		—		(11.5)		(130.0)
Proved oil and natural gas properties	(11,275.7)		(3,412.0)		(47.0)		(14,734.7)
Net capitalized costs	$	6,230.4	$	1,459.8	$	396.9	$	8,087.1
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

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2025

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)	2025		2024
Balance at beginning of year	$	1,008,884	$	914,763
Accretion	57,730		52,511
Liabilities incurred	20,744		25,619

Revisions of previous estimates	(12,094)		29,279
Liabilities settled	(70,829)		(1,898)


Changes due to translation of foreign currencies	8,432		(11,390)
Balance at end of period	1,012,867		1,008,884
Current portion of liability	(41,959)		(48,080)
Non-current portion of liability	$	970,908	$	960,804

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.

Employee and Retiree Benefit Plans - Schedule of Fair Value Measurements of Retirement Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	$ 527,079	$ 492,120
Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	310,972	284,256
Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	167,196	189,849
Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	48,911	18,014
United States
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	416,798	388,675
United States \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	310,972	284,256
United States \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	74,837	103,453
United States \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	30,989	965
United States \| U.S. core equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	83,956	87,124
United States \| U.S. core equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	73,999	87,124
United States \| U.S. core equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| U.S. core equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	9,957	0
United States \| U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	56,699	51,978
United States \| U.S. small/midcap \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	56,699	51,978
United States \| U.S. small/midcap \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| U.S. small/midcap \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| Other alternative strategies
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	21,032	965
United States \| Other alternative strategies \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| Other alternative strategies \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| Other alternative strategies \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	21,032	965
United States \| International equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	27,772	22,724
United States \| International equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	27,772	22,724
United States \| International equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| International equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| Emerging market equity
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	13,518	7,638
United States \| Emerging market equity \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	13,518	7,638
United States \| Emerging market equity \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| Emerging market equity \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	186,995	208,755
United States \| U.S. fixed income \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	119,205	105,302
United States \| U.S. fixed income \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	67,790	103,453
United States \| U.S. fixed income \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| International commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	7,047
United States \| International commingled trust fund \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0
United States \| International commingled trust fund \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	7,047
United States \| International commingled trust fund \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0
United States \| Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	19,779	9,491
United States \| Cash and equivalents \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	19,779	9,491
United States \| Cash and equivalents \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	0	0
United States \| 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	110,281	103,445
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	92,359	86,396
Foreign Plans \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	17,922	17,049
Foreign Plans \| Cash and equivalents
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	4,771	4,465
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	4,771	4,465
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	13,946	14,377
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	13,946	14,377
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	30,986	26,500
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	30,986	26,500
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	42,124	41,054
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	42,124	41,054
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	18,454	17,049
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	532	0
Foreign Plans \| Other \| Level 3
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets	$ 17,922	$ 17,049

Supplemental Oil and Gas Information (Unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2025 $ / bbl ft³	Dec. 31, 2024 $ / bbl	Dec. 31, 2023 $ / bbl
Oil and Gas, Proved Reserve, Quantity [Line Items]
Future net cash flows annual discount factor, percentage	10.00%
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)	65.34	75.48	78.22
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)	3.39	2.13	2.64

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Name Form 20-F
-Number Part II
-Section Item 18
-Subparagraph (Instruction 2)
-Publisher SEC

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 55
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477916/932-235-55-2

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-5

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-4

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
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+ Details

Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025		2024		2023
Compensation charged against income before income tax benefit	$	50,107	$	40,831	$	58,760
Related income tax benefit recognized in income	6,438		5,513		9,330

Schedule of Assumptions used in Valuation of Performance Awards Granted

The assumptions used in the valuation of the performance awards granted in 2025, 2024 and 2023 are presented in the following table.


	2025	2024	2023
Fair value per share at grant date	$19.65 - $22.11	$41.95	$60.46
Assumptions
Expected volatility	40.00%	50.00%	81.00%
Risk-free interest rate	4.25%	4.14%	3.90%
Stock beta	0.980	1.062	1.034
Expected life	3.0 years	3.0 years	3.0 years

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	2025	2024	2023
Non-Employee Directors 1	Closing Stock Price at Grant Date	$22.50 - $31.25	$30.26 - $45.70	$43.27
Long-Term Incentive Plan 2	Average High/Low Stock Price at Grant Date	$23.09 - $25.98	$37.78 - $45.98	$42.20

1 Under the 2021 NED Plan, RSUs granted in 2025 are scheduled to vest in February 2026.

2 The RSUs granted under the 2020 Long-Term Plan and the 2025 Long-Term Plan generally vest on the third anniversary of the date of grant.

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)	2025	2024	2023
Outstanding at beginning of year	1,392,421	1,818,188	2,148,467
Granted	657,730	536,900	409,160
Vested and issued	(481,670)	(938,599)	(408,135)
Forfeited	(104,966)	(24,068)	(331,304)
Outstanding at end of year	1,463,515	1,392,421	1,818,188

Changes in RSUs outstanding for each of the last three years are presented in the following table.


(Number of share units)	2025	2024	2023
Outstanding at beginning of year	1,558,600	1,219,584	1,227,792
Granted	559,284	741,228	556,100
Vested and issued	(360,281)	(330,444)	(517,047)
Forfeited	(95,951)	(71,768)	(47,261)
Outstanding at end of year	1,661,652	1,558,600	1,219,584

Supplemental Quarterly Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Interim Reporting [Line Items]
Revenue from contracts with customers	$ 613,100	$ 721,000	$ 683,000	$ 672,700	$ 669,600	$ 753,200	$ 801,000	$ 794,800	$ 2,689,845	$ 3,018,598	$ 3,448,854
Income from continuing operations before income taxes	28,900	(3,700)	34,900	122,800	78,600	153,800	189,600	145,600	182,866	567,569	921,069
Income from continuing operations	22,300	(7,800)	33,800	90,000	65,200	151,700	156,900	115,500	138,314	489,297	725,148
Net income (loss) including noncontrolling interest	22,600	(8,300)	35,100	89,400	64,400	151,100	156,300	114,700	138,799	486,485	723,681
Net income (loss) attributable to Murphy	$ 11,900	$ (3,000)	$ 22,300	$ 73,000	$ 50,300	$ 139,100	$ 127,700	$ 90,000	$ 104,234	$ 407,171	$ 661,559
Income from continuing operations per common share
Basic (in USD per share)	$ 0.08	$ (0.02)	$ 0.15	$ 0.51	$ 0.35	$ 0.93	$ 0.84	$ 0.60	$ 0.73	$ 2.73	$ 4.27
Diluted (in USD per share)	0.08	(0.02)	0.15	0.50	0.34	0.93	0.83	0.60	0.72	2.72	4.23
Net income per common share
Basic (in USD per share)	0.08	(0.02)	0.16	0.51	0.35	0.93	0.84	0.59	0.73	2.71	4.26
Diluted (in USD per share)	0.08	(0.02)	0.16	0.50	0.34	0.93	0.83	0.59	0.72	2.70	4.22
Cash dividend per Common share (in USD per share)	$ 0.325	$ 0.325	$ 0.325	$ 0.325	$ 0.300	$ 0.300	$ 0.300	$ 0.300	$ 1.300	$ 1.200	$ 1.100
Minimum
Interim Reporting [Line Items]
Income from continuing operations before income taxes									$ 182,900	$ 567,600
Net income (loss) attributable to Murphy										407,100
Maximum
Interim Reporting [Line Items]
Income from continuing operations									138,300	$ 489,300
Net income (loss) attributable to Murphy									$ 104,200

Incentive Plans - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed	$ 46.5
Settlement period of phantom units	2 years
Stock options exercised (in shares)			11,000
Stock options forfeited (in shares)			2,000
Exercised (in USD per share)			$ 28.51
Stock options outstanding (in shares)			0
Cash settled awards	$ 7.5	$ 1.7	$ 29.4
Incentive compensation plan expense	$ 37.8	$ 37.1	$ 30.9
Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
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
2025 Long-Term Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares available for issuance (in shares)	3,885,000
Number of shares available (in shares)	3,872,000

Leases - Narrative (Details)	12 Months Ended
Leases - Narrative (Details)	Dec. 31, 2025
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	15 years

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	$ 229.7	$ 283.0
Proved oil and natural gas properties	22,722.1	21,343.6
Gross capitalized costs	22,951.8	21,626.6
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(130.0)	(131.7)
Proved oil and natural gas properties	(14,734.7)	(13,486.6)
Net capitalized costs	8,087.1	8,008.3
United States
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	207.0	247.3
Proved oil and natural gas properties	17,417.6	16,598.8
Gross capitalized costs	17,624.6	16,846.1
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(118.5)	(111.0)
Proved oil and natural gas properties	(11,275.7)	(10,326.2)
Net capitalized costs	6,230.4	6,408.9
Canada
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	6.4	6.6
Proved oil and natural gas properties	4,865.4	4,498.1
Gross capitalized costs	4,871.8	4,504.7
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	0.0	0.0
Proved oil and natural gas properties	(3,412.0)	(3,116.2)
Net capitalized costs	1,459.8	1,388.5
Other
Oil and Gas, Capitalized Cost [Line Items]
Unproved oil and natural gas properties	16.3	29.1
Proved oil and natural gas properties	439.1	246.7
Gross capitalized costs	455.4	275.8
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(11.5)	(20.7)
Proved oil and natural gas properties	(47.0)	(44.2)
Net capitalized costs	$ 396.9	$ 210.9

Employee and Retiree Benefit Plans

12 Months Ended

Dec. 31, 2025

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 Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Change in benefit obligation
Obligation at January 1	$	655,324	$	699,151	$	54,994	$	63,808
Service cost	7,094		7,042		382		436
Interest cost	33,798		33,554		3,261		2,923
Participant contributions	—		—		2,762		2,730
Actuarial (gain) loss 1	1,175		(35,417)		17,681		825
Medicare Part D subsidy	—		—		383		358
Exchange rate changes	8,010		(3,263)		9		(14)
Benefits paid	(45,907)		(45,743)		(16,073)		(16,072)




Obligation at December 31	659,494		655,324		63,399		54,994
Change in plan assets
Fair value of plan assets at January 1	492,120		477,809		—		—
Actual return on plan assets	48,285		27,317		—		—
Employer contributions	25,067		35,477		12,928		12,984
Participant contributions	—		—		2,762		2,730
Medicare Part D subsidy	—		—		383		358
Exchange rate changes	7,514		(2,740)		—		—
Benefits paid	(45,907)		(45,743)		(16,073)		(16,072)

Fair value of plan assets at December 31	527,079		492,120		—		—
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	14,925		1,819		—		—
Other accrued liabilities	(10,354)		(10,617)		(4,663)		(4,237)
Deferred credits and other liabilities	(136,986)		(154,406)		(58,736)		(50,757)
Fund Status and net plan liability recognized at December 31	$	(132,415)	$	(163,204)	$	(63,399)	$	(54,994)

1 Actuarial losses in 2025 for other post retirement benefits primarily relate to trend rate increases for incurred claims. Actuarial gains for pension benefits in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation.

At December 31, 2025, 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 Benefits		Other Postretirement Benefits
Net actuarial gain (loss)	$	(148,280)	$	18,862
Prior service (credit) cost	(16,320)		2,873
	$	(164,600)	$	21,735

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 Benefit Obligations				Accumulated Benefit Obligations				Fair Value of Plan Assets
(Thousands of dollars)	2025		2024		2025		2024		2025		2024
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	—	$	497,947	$	—	$	489,225	$	—	$	477,983
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets	147,339		145,058		145,545		143,859		—		—
Unfunded other postretirement plans	63,399		54,994		63,399		54,994		—		—

The table that follows provides the components of net periodic benefit expense for each of the three years presented.


	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2023		2025		2024		2023
Service cost	$	7,094	$	7,042	$	6,542	$	382	$	436	$	495
Interest cost	33,798		33,554		34,140		3,261		2,923		3,241
Expected return on plan assets	(35,511)		(33,427)		(32,839)		—		—		—

Amortization of prior service cost (credit)	1,967		2,316		620		(532)		(532)		(532)

Recognized actuarial (gain) loss	7,262		9,438		9,776		(3,182)		(3,586)		(3,512)
Net periodic benefit cost (credit)	14,610		18,923		18,239		(71)		(759)		(308)

Other pension costs	276		251		219		—		—		—
Total net periodic benefit cost (credit)	$	14,886	$	19,174	$	18,458	$	(71)	$	(759)	$	(308)

The preceding tables in this note include the following amounts related to foreign benefit plans.


	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Benefit obligation at December 31	$	109,883	$	115,428	$	90	$	106
Fair value of plan assets at December 31	110,280		103,445		—		—
Net plan liabilities recognized	397		(11,983)		(90)		(106)
Net periodic benefit (credit) expense	2,131		1,480		(35)		(44)

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2025 and 2024 and net periodic benefit expense for 2025 and 2024.


	Benefit Obligations								Net Periodic Benefit Expense
	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,				Year				Year
	2025		2024		2025		2024		2025		2024		2025		2024
Discount rate on obligation, interest cost and service cost	5.41	%	5.58	%	5.48	%	5.65	%	5.54	%	5.17	%	5.66	%	5.15	%
Rate of compensation increase	3.50	%	3.38	%	—		—		3.50	%	3.50	%	—		—
Cash balance interest credit rate	3.70	%	3.20	%	—		—		—		—		—		—
Expected return on plan assets	—		—		—		—		7.29	%	7.19	%	—		—

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 Benefits		Other Postretirement Benefits
2026	$	49,819	$	4,663
2027	51,276		4,710
2028	51,786		4,872
2029	51,646		4,772
2030	53,230		4,752
2031-2035	260,581		23,671

For purposes of measuring postretirement benefit obligations at December 31, 2025, the future annual rates of increase in the cost of health care were assumed to be 7.9% for 2026 decreasing each year to an ultimate rate of 4.0% in 2050 and thereafter.

During 2025, the Company made contributions of $24.3 million to its domestic defined benefit pension plans and $12.9 million to its domestic postretirement benefits plan. During 2026, the Company currently expects to make contributions of $23.8 million to its domestic defined benefit pension plans, $0.8 million to its foreign defined benefit pension plans and $4.7 million to its domestic postretirement benefits plan.

PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy 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,
	2025		2024
Equity securities	45.2	%	57.3	%
Fixed income securities	42.7	%	36.2	%
Alternatives	7.4	%	3.7	%
Cash equivalents	4.7	%	2.8	%
	100.0	%	100.0	%

The Company’s weighted average expected return on plan assets was 7.3% in 2025 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 7.3% expected return was comprised of the weighted average expected future equity securities return of 7.6% and a fixed income securities return of 5.0%. An average expected investment expense of 0.5% is included in this calculation. Over the last 10 years, the return on funded retirement plan assets has averaged 4.1%.

At December 31, 2025, 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, 2025		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	83,956	$	73,999	$	—	$	9,957
U.S. small/midcap	56,699		56,699		—		—
Other alternative strategies	21,032		—		—		21,032
International equity	27,772		27,772		—		—
Emerging market equity	13,518		13,518		—		—
Fixed income securities:
U.S. fixed income	186,995		119,205		67,790		—
International commingled trust fund	7,047		—		7,047		—

Cash and equivalents	19,779		19,779		—		—
Total Domestic Plans	416,798		310,972		74,837		30,989
Foreign Plans
Equity securities funds	13,946		—		13,946		—
Fixed income securities funds	30,986		—		30,986		—
Diversified pooled fund	42,124		—		42,124		—
Other	18,454		—		532		17,922
Cash and equivalents	4,771		—		4,771		—
Total Foreign Plans	110,281		—		92,359		17,922
Total	$	527,079	$	310,972	$	167,196	$	48,911

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, 2024		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	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

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 four investments. The Company's domestic level 3 investments primarily relate to funds which invest primarily in U.S. middle-market companies using various types of credit instruments.

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 Alternative Strategies
Total at December 31, 2023	$	24,454
Actual return (loss) on plan assets 1:
Relating to assets held at the reporting date	(3,574)

Purchases, sales and settlements	(2,865)
Total at December 31, 2024	18,015
Actual return on plan assets 1:
Relating to assets held at the reporting date	2,394

Purchases, sales and settlements	28,502
Total at December 31, 2025	$	48,911

1 Gains and losses on Level 3 plan assets are recognized in the Consolidated Statements of Comprehensive Income (Loss) under the caption "Retirement and postretirement benefit plans.”

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 plan, with a maximum match of 6.0%. Amounts charged to expense for the Company’s match to these plans were $9.1 million in 2025, $8.7 million in 2024 and $8.5 million in 2023.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (p)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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-Name Accounting Standards Codification
-Section 55
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-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Section 50
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Section 50
-Paragraph 1
-Subparagraph (l)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Assets and Liabilities Measured at Fair Value

12 Months Ended

Dec. 31, 2025

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, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total





Liabilities:
Nonqualified employee savings plan	$	22,205	$	—	$	—	$	22,205	$	19,469	$	—	$	—	$	19,469


Commodity swaps	—		—		—		—		—		1,707		—		1,707
	$	22,205	$	—	$	—	$	22,205	$	19,469	$	1,707	$	—	$	21,176

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.

As of December 31, 2025, there were no outstanding commodity (NYMEX Henry Hub natural gas) swaps subject to fair value measurement. The liabilities associated with these contacts have been finalized as of December 31, 2025 and were based on realized NYMEX Henry Hub pricing. 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 was recorded in “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations.

The Company was previously exposed to contingent consideration payments related to a prior asset purchase agreement, which required additional payments contingent on specified revenue thresholds and project milestones being met. At December 31, 2022, the Company’s liabilities were finalized and no longer subject to fair value measurement. Final cash payment was made in 2023 and was recorded to “Contingent consideration payment“ in the Consolidated Statements of Cash Flows.

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, 2025 and 2024.


	December 31,
	2025				2024
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,385,080	$	1,326,101	$	1,275,374	$	1,185,961

Fair Values – Nonrecurring

Impairment expenses of $115.0 million and $62.9 million were incurred in 2025 and 2024, respectively. In 2025, an impairment charge of $115.0 million ($92.0 million excluding NCI) was recorded for the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation. In 2024, an impairment charge of $34.5 million was recorded for the Calliope field and an impairment charge of $28.4 million was recorded for the Nearly Headless Nick field, in the Gulf of America. Both impairment charges were due to operational issues that led to reserve reductions.

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 tables.


	Year Ended December 31, 2025
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3








Assets:
Impaired proved properties
United States - Offshore	$	—	$	—	$	42,397	$	157,399	$	115,002


	Year Ended December 31, 2024
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3








Assets:
Impaired proved properties
United States - Offshore	$	—	$	—	$	501	$	63,410	$	62,909

Environmental and Other Contingencies	12 Months Ended
Environmental and Other Contingencies	Dec. 31, 2025
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; trade policies, tariffs and other trade restrictions; 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 of 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 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. In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the 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 EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034. 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. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the GHGRP for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. The repeal calls into question the EPA’s authority to regulate GHGs, as well as the EPA’s prior scientific assessment of climate change risks. Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact the EPA’s regulation of GHG emissions going forward. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions. 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.

- Definition

The entire disclosure for environmental loss contingencies, such as presence of hazardous waste, relevant information from reports issued by regulators, and estimated costs to achieve compliance with regulatory requirements. This element may be used for all of an entity's disclosures about environmental loss contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 410
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Subparagraph (d)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481931/410-30-50-10

Reference 2: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 410
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-Name Accounting Standards Codification
-Section 50
-Paragraph 10
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481931/410-30-50-10

Reference 3: http://www.xbrl.org/2003/role/exampleRef
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-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481899/410-30-55-11

Reference 4: http://www.xbrl.org/2003/role/exampleRef
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-SubTopic 30
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-Section 55
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481899/410-30-55-16

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-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/410-30/tableOfContent

Reference 6: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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-Paragraph 10
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481931/410-30-50-10

Reference 7: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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-Section 50
-Paragraph 10
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-URI https://asc.fasb.org/1943274/2147481931/410-30-50-10

Reference 8: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 410
-SubTopic 30
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-Paragraph 10
-Subparagraph (c)
-Publisher FASB
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Reference 9: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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-SubTopic 30
-Name Accounting Standards Codification
-Section 50
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-URI https://asc.fasb.org/1943274/2147481931/410-30-50-10

Reference 11: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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Reference 14: http://www.xbrl.org/2003/role/exampleRef
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-Section 55
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481899/410-30-55-17

+ Details

Common Stock Issued and Outstanding (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025	2024	2023
Beginning of year	145,845,124	152,748,642	155,467,319
Stock options exercised 1	—	—	2,657
Restricted stock awards 1	553,478	1,105,268	689,824

Treasury shares purchased	(3,613,450)	(8,008,786)	(3,411,158)
End of year	142,785,152	145,845,124	152,748,642

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.

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 1,008,884	$ 914,763
Accretion	57,730	52,511	$ 46,059
Liabilities incurred	20,744	25,619
Revisions of previous estimates	(12,094)	29,279
Liabilities settled	(70,829)	(1,898)
Changes due to translation of foreign currencies	8,432	(11,390)
Balance at end of period	$ 1,012,867	$ 1,008,884	$ 914,763

Financing Arrangements and Debt - Schedule of Long Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Total notes payable	$ 1,284,832	$ 1,284,832
Unamortized debt issuance cost and discount on notes payable	(12,406)	(14,336)
Total notes payable, net of unamortized discount	1,272,426	1,270,496
Finance lease obligations, due through November 2034	12,654	4,877
Total debt including current maturities	1,285,080	1,275,373
Senior Unsecured Revolving Credit Facility	100,000	0
Current maturities	$ (2,514)	$ (871)
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation
Long-term debt, including finance lease obligation	$ 1,382,566	$ 1,274,502
5.875% notes, due December 2027 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	5.875%
Total notes payable	$ 78,899	78,899
6.375% notes, due July 2028 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.375%
Total notes payable	$ 148,590	148,590
7.050% notes, due May 2029 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	7.05%
Total notes payable	$ 117,582	117,582
6.000% notes, due October 2032 \| Senior Notes
Debt Instrument [Line Items]
Stated interest rate	6.00%
Total notes payable	$ 600,000	600,000
5.875% Notes, Due December 2042
Debt Instrument [Line Items]
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%
Total notes payable	$ 339,761	$ 339,761

Income Taxes - Schedule of Cash Taxes Paid, Net of Refunds (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Effective Income Tax Rate Reconciliation [Line Items]
Total U.S. State and Local	$ (318)	$ 2,300	$ 5,968
Total Foreign	6,419	10,348	6,388
Total	6,101	12,648	12,356
Alabama
Effective Income Tax Rate Reconciliation [Line Items]
Total U.S. State and Local	(1,868)	0	4,838
Texas
Effective Income Tax Rate Reconciliation [Line Items]
Total U.S. State and Local	1,500	2,300	1,079
Other
Effective Income Tax Rate Reconciliation [Line Items]
Total U.S. State and Local	50	0	51
Canada
Effective Income Tax Rate Reconciliation [Line Items]
Total Foreign	2,929	6,480	3,553
Canada - Alberta
Effective Income Tax Rate Reconciliation [Line Items]
Total Foreign	2,809	3,269	1,756
Brunei
Effective Income Tax Rate Reconciliation [Line Items]
Total Foreign	$ 681	$ 599	$ 1,079

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Property acquisition costs
Unproved	$ 5.5	$ 8.0	$ 8.5
Proved	23.6	0.0	27.1
Total acquisition costs	29.1	8.0	35.6
Exploration costs	216.2	145.9	198.1
Development costs	951.6	781.5	880.8
Total costs incurred	1,196.9	935.4	1,114.5
Charged to expense
Dry hole expense	30.1	73.2	169.8
Geophysical and other costs	69.9	50.8	54.1
Total charged to expense	100.0	124.0	223.9
Property additions	1,096.9	811.4	890.6
Undeveloped lease amortization	11.7	9.6	10.9
United States
Property acquisition costs
Unproved	5.5	7.8	0.0
Proved	23.6	0.0	12.8
Total acquisition costs	29.1	7.8	12.8
Exploration costs	71.6	85.3	157.8
Development costs	696.2	598.7	667.2
Total costs incurred	796.9	691.8	837.8
Charged to expense
Dry hole expense	(0.9)	70.9	153.1
Geophysical and other costs	34.3	19.2	13.4
Total charged to expense	33.4	90.1	166.5
Property additions	763.5	601.7	671.3
Canada
Property acquisition costs
Unproved	0.0	0.2	0.0
Proved	0.0	0.0	0.0
Total acquisition costs	0.0	0.2	0.0
Exploration costs	0.3	0.4	0.4
Development costs	152.5	137.7	206.2
Total costs incurred	152.8	138.3	206.6
Charged to expense
Dry hole expense	0.0	0.0	0.0
Geophysical and other costs	0.3	0.4	0.4
Total charged to expense	0.3	0.4	0.4
Property additions	152.5	137.9	206.2
Other
Property acquisition costs
Unproved	0.0	0.0	8.5
Proved	0.0	0.0	14.3
Total acquisition costs	0.0	0.0	22.8
Exploration costs	144.3	60.2	39.9
Development costs	102.9	45.1	7.4
Total costs incurred	247.2	105.3	70.1
Charged to expense
Dry hole expense	31.0	2.3	16.7
Geophysical and other costs	35.3	31.2	40.3
Total charged to expense	66.3	33.5	57.0
Property additions	$ 180.9	$ 71.8	$ 13.1

Business Segments - Schedule of Geographic Information on Certain Long-Lived Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 8,136.3	$ 8,054.6	$ 8,225.1
UNITED STATES
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	6,236.8	6,415.9	6,555.0
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	1,460.6	1,389.5	1,497.3
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain long-lived assets	$ 438.9	$ 249.2	$ 172.8

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Cost	$ 23,204,495	$ 21,866,192
Net	8,136,346	8,054,653
Exploration and production
Property, Plant and Equipment [Line Items]
Cost	23,042,373	21,716,358
Net	8,099,291	8,021,620
Corporate and other
Property, Plant and Equipment [Line Items]
Cost	162,122	149,834
Net	37,055	33,033
Mineral Rights
Property, Plant and Equipment [Line Items]
Cost	229,759	283,015
Net	99,729	151,341
Administrative Assets and Support Equipment
Property, Plant and Equipment [Line Items]
Net	$ 12,050	$ 13,335

Inventories (Tables)

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventories consisted of the following for the respective periods presented.


	December 31,
(Thousands of dollars)	2025		2024
Unsold crude oil	$	17,560	$	18,745
Materials and supplies	39,724		36,113
Inventories	$	57,284	$	54,858

Financing Arrangements and Debt - Narrative (Details)			1 Months Ended			12 Months Ended
Financing Arrangements and Debt - Narrative (Details)	Jan. 23, 2026 USD ($)	Jan. 02, 2026 USD ($)	Jan. 31, 2026 USD ($)	Oct. 31, 2024 USD ($)	May 31, 2024 USD ($)	Dec. 31, 2025 USD ($) revenueStream	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Jan. 30, 2026 USD ($)	Oct. 03, 2024 USD ($)
Debt Instrument [Line Items]
Future maturities of long term debt in 2026						$ 0
Future maturities of long term debt in 2027						78,900,000
Future maturities of long term debt in 2028						148,600,000
Future maturities of long term debt in 2029						217,600,000
Future maturities of long term debt in 2030						0
Future maturities of long term debt, thereafter						939,800,000
Amount outstanding						100,000,000	$ 0
Debt extinguishment cost						0	15,700,000	$ 0
Senior Notes
Debt Instrument [Line Items]
Repurchase amount				$ 521,100,000	$ 50,500,000
Senior Notes \| 6.000 Notes Due 2032
Debt Instrument [Line Items]
Transaction costs										$ 10,100,000
Debt instrument, face amount										$ 600,000,000.0
Stated interest rate										6.00%
Senior Notes \| 5.875 Notes Due 2027
Debt Instrument [Line Items]
Repurchase amount				258,800,000	26,500,000		79,000,000.0
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 \| Subsequent Event
Debt Instrument [Line Items]
Extinguishment of debt	$ 227,500,000
Senior Notes \| Subsequent Event \| 6.500 Notes Due 2034
Debt Instrument [Line Items]
Transaction costs	8,300,000
Debt instrument, face amount	$ 500,000,000.0
Stated interest rate	6.50%
Senior Notes \| Subsequent Event \| 5.875 Notes Due 2027
Debt Instrument [Line Items]
Repurchase amount	$ 78,900,000
Senior Notes \| Subsequent Event \| 6.375 Notes Due 2028
Debt Instrument [Line Items]
Cost of debt extinguishment	3,500,000
Non - cash debt extinguishment	1,000,000.0
Extinguishment of debt	148,600,000
Additional cash cost	$ 2,500,000
Revolving Credit Facility
Debt Instrument [Line Items]
Amount outstanding						$ 100,000,000.0
Interest rate on credit facility						6.04%
Revolving Credit Facility \| Adjusted Daily Simple SOFR Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						1.00%
Revolving Credit Facility \| Base Rate
Debt Instrument [Line Items]
Stated interest rate						0.50%
Revolving Credit Facility \| Subsequent Event
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 2,000,000,000.0						$ 1,350,000,000
Amount outstanding		$ 2,000,000,000.00
Transaction costs			12,300,000
Extinguishment of debt			100,000,000.0
Revolving Credit Facility \| Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, consolidated total capitalization percentage						60.00%
Debt instrument, period of adjusted SOFR published \| revenueStream						2
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 \| Unsecured Debt \| Subsequent Event
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 1,350,000,000
Revolving Credit Facility \| Unsecured Debt \| Subsequent Event \| Adjusted Daily Simple SOFR Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		0.00%
Revolving Credit Facility \| Unsecured Debt \| Subsequent Event \| Daily Simple SOFR
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		0.00%
Revolving Credit Facility \| Letter of Credit
Debt Instrument [Line Items]
Amount outstanding						$ 400,000

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, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.30%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.41%	5.58%
Net periodic benefit expense, discount rate	5.54%	5.17%
Benefit obligation, rate of compensation increase	3.50%	3.38%
Net periodic benefit expense, rate of compensation increase	3.50%	3.50%
Benefit obligation, cash balance interest credit rate	3.70%	3.20%
Net periodic benefit cost, cash balance interest credit rate	0.00%	0.00%
Benefit obligation, expected return on Plan assets	0.00%	0.00%
Expected return on plan assets	7.29%	7.19%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligations, discount rate	5.48%	5.65%
Net periodic benefit expense, discount rate	5.66%	5.15%
Benefit obligation, rate of compensation increase	0.00%	0.00%
Net periodic benefit expense, rate of compensation increase	0.00%	0.00%
Benefit obligation, cash balance interest credit rate	0.00%	0.00%
Net periodic benefit cost, cash balance interest credit rate	0.00%	0.00%
Benefit obligation, expected return on Plan assets	0.00%	0.00%
Expected return on plan assets	0.00%	0.00%

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Firm ID	185
Auditor Name	KPMG LLP
Auditor Location	Houston, Texas

Leases

12 Months Ended

Dec. 31, 2025

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 15 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 (both short-term and long-term) included in the Consolidated Financial Statements are as follows.


		Year Ended December 31,
(Thousands of dollars)	Financial Statements Category	2025		2024
Operating lease 1, 2	Lease operating expenses	$	342,520	$	411,303
Operating lease 2	Transportation, gathering and processing	8,308		16,117
Operating lease 2	Selling and general expenses	10,405		10,990
Operating lease 2	Other operating expense	467		6,622
Operating lease 2	Exploration expenses	14,335		38,974

Operating lease 2	Property, plant and equipment	175,400		277,170
Operating lease 2	Asset retirement obligations	85,690		10
Finance lease
Amortization of asset	Depreciation, depletion and amortization	1,026		855
Interest on lease liabilities	Interest expense, net	229		193
Sublease income	Other income	(240)		(1,143)
Net lease expense		$	638,140	$	761,091

1 Variable lease expenses. For the years ended December 31, 2025 and 2024, included variable lease expenses of $34.6 million and $42.3 million, respectively, primarily related to operating costs at a natural gas processing plant in our Canada Onshore business.

2 Short-term leases due within 12 months. The table below shows amounts included in the Consolidated Financial Statements related to short-term leases due within 12 months. These expenses primarily related to drilling rigs and other oil and natural gas field equipment.


(Thousands of dollars)	Year Ended December 31,
Financial Statements Category	2025		2024
Lease operating expenses	$	159,746	$	236,402
Transportation, gathering and processing	8,308		12,993
Selling and general expenses	1,918		772
Other operating expense	16		6,230
Exploration expenses	13,211		38,500

Property, plant and equipment	96,909		97,104
Asset retirement obligations	65,418		10
Total short-term lease expense	$	345,526	$	392,011

Maturity of Lease Liabilities


(Thousands of dollars)	Operating Leases		Finance Leases		Total
2026	$	315,609	$	3,302	$	318,911
2027	146,130		3,302		149,432
2028	63,009		3,302		66,311
2029	60,214		2,491		62,705
2030	58,445		1,885		60,330
Remaining	366,321		774		367,095
Total future minimum lease payments	1,009,728		15,056		1,024,784
Less imputed interest	(193,121)		(2,402)		(195,523)
Present value of lease liabilities 1	$	816,607	$	12,654	$	829,261

1 Includes both the current and long-term portion of the lease liabilities.

Lease Term and Discount Rate


	December 31, 2025		December 31, 2024
Weighted average remaining lease term:
Operating leases	7 years		8 years
Finance leases	5 years		6 years
Weighted average discount rate:
Operating leases	5.5	%	5.7	%
Finance leases	5.4	%	4.9	%

Other Information


	Year Ended December 31,
(Thousands of dollars)	2025		2024
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	258,564	$	328,847
Operating cash flows from finance leases	339		311
Financing cash flows from finance leases	1,238		665
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases ¹	$	247,566	$	349,312
Finance leases 2	8,845		1,749

1 For the year ended December 31, 2025, right-of-use assets, obtained in exchange for operating lease liabilities, primarily included $153.7 million for a drill ship operating lease extension used in our U.S. Offshore business and $72.2 million for a drilling rig and two support vessels in our Vietnam business. December 31, 2024 included $254.1 million for a drill ship operating lease extension in our U.S. Offshore business and $52.7 million related to two drilling rigs and several natural gas compressors in our U.S. Onshore business.

2 For the year ended December 31, 2025, right-of-use assets obtained in exchange for finance lease liabilities primarily included $8.8 million related to computing equipment in the U.S.

Leases

Note T – Leases

Nature of Leases

Remaining lease terms range from 1 year to 15 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.

Related Expenses

Expenses related to finance and operating leases (both short-term and long-term) included in the Consolidated Financial Statements are as follows.


		Year Ended December 31,
(Thousands of dollars)	Financial Statements Category	2025		2024
Operating lease 1, 2	Lease operating expenses	$	342,520	$	411,303
Operating lease 2	Transportation, gathering and processing	8,308		16,117
Operating lease 2	Selling and general expenses	10,405		10,990
Operating lease 2	Other operating expense	467		6,622
Operating lease 2	Exploration expenses	14,335		38,974

Operating lease 2	Property, plant and equipment	175,400		277,170
Operating lease 2	Asset retirement obligations	85,690		10
Finance lease
Amortization of asset	Depreciation, depletion and amortization	1,026		855
Interest on lease liabilities	Interest expense, net	229		193
Sublease income	Other income	(240)		(1,143)
Net lease expense		$	638,140	$	761,091


(Thousands of dollars)	Year Ended December 31,
Financial Statements Category	2025		2024
Lease operating expenses	$	159,746	$	236,402
Transportation, gathering and processing	8,308		12,993
Selling and general expenses	1,918		772
Other operating expense	16		6,230
Exploration expenses	13,211		38,500

Property, plant and equipment	96,909		97,104
Asset retirement obligations	65,418		10
Total short-term lease expense	$	345,526	$	392,011

Maturity of Lease Liabilities


(Thousands of dollars)	Operating Leases		Finance Leases		Total
2026	$	315,609	$	3,302	$	318,911
2027	146,130		3,302		149,432
2028	63,009		3,302		66,311
2029	60,214		2,491		62,705
2030	58,445		1,885		60,330
Remaining	366,321		774		367,095
Total future minimum lease payments	1,009,728		15,056		1,024,784
Less imputed interest	(193,121)		(2,402)		(195,523)
Present value of lease liabilities 1	$	816,607	$	12,654	$	829,261

1 Includes both the current and long-term portion of the lease liabilities.

Lease Term and Discount Rate


	December 31, 2025		December 31, 2024
Weighted average remaining lease term:
Operating leases	7 years		8 years
Finance leases	5 years		6 years
Weighted average discount rate:
Operating leases	5.5	%	5.7	%
Finance leases	5.4	%	4.9	%

Other Information


	Year Ended December 31,
(Thousands of dollars)	2025		2024
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	258,564	$	328,847
Operating cash flows from finance leases	339		311
Financing cash flows from finance leases	1,238		665
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases ¹	$	247,566	$	349,312
Finance leases 2	8,845		1,749

2 For the year ended December 31, 2025, right-of-use assets obtained in exchange for finance lease liabilities primarily included $8.8 million related to computing equipment in the U.S.

Significant Accounting Polices	12 Months Ended
Significant Accounting Polices	Dec. 31, 2025
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 oil and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties, in which Murphy shares in the undivided interest with other producers, are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The Company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2025 and 2024, 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, 2025 and 2024, 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. 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 the criteria of 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”, “Transportation, gathering and processing”, “Exploration expenses”, “Other operating 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 Statements 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 the 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 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. Certain physical delivery sale and purchase contracts are entered into in the normal course of business and qualify for, and are designated under, the normal purchase and normal sale scope exception provided by ASC 815, “Derivatives and Hedging”. Accordingly, these contracts are not accounted for as derivative instruments or recorded at fair value in the Consolidated Balance Sheets. Revenues and expenses associated with these contracts are recognized in net income (loss) when the underlying physical transactions occur. 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 or three years. The Company estimates the number of stock options and PSUs that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense, when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (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 Statements of Operations are recorded net of tax in “Accumulated other comprehensive loss”. The remaining amounts in “Accumulated other comprehensive loss” include net actuarial losses and prior service (cost) credit. See Note J. NET INCOME (LOSS) PER COMMON SHARE – Basic 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.

Incentive Plans - Schedule of Assumptions used in Valuation of Performance Awards Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
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	40.00%	50.00%	81.00%
Risk-free interest rate	4.25%	4.14%	3.90%
Stock beta	0.980	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)	$ 19.65
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)	22.11
Time lapse restricted stock \| Non-Employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)			$ 43.27
Time lapse restricted stock \| Non-Employee Directors \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	22.50	$ 30.26
Time lapse restricted stock \| Non-Employee Directors \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date (in USD per share)	31.25	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)	23.09	37.78
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)	$ 25.98	$ 45.98

Other Financial Information - Schedule of Noncash Operating Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$ (75,437)	$ 71,081	$ 47,151
(Increase) decrease in inventories	(1,461)	1,327	329
(Increase) decrease in prepaid expenses	539	1,192	(1,293)
Increase (decrease) in accounts payable and accrued liabilities	3,101	3,287	(140,011)
Increase (decrease) in income taxes payable	(794)	(2,004)	(5,537)
Net (increase) decrease in noncash working capital	(74,052)	74,883	(99,361)
Supplementary disclosures:
Capitalized interest paid	8,800	11,400	14,500
Interest paid, net of amounts capitalized	88,119	78,806	108,912
Non-cash investing activities:
Asset retirement costs capitalized	9,629	47,233	32,975
(Increase) decrease in capital expenditure accrual	(98,778)	(5,935)	17,517
Net cash income taxes paid	$ 6,101	$ 12,648	$ 12,356

Supplemental Oil and Gas Information (Unaudited) - Schedule of Proved Reserves Based on Average Prices (Details) MMBbls in Millions, ft³ in Billions	12 Months Ended
	Dec. 31, 2025 ft³ MMBbls	Dec. 31, 2025 ft³ MMBbls	Dec. 31, 2024 ft³ MMBbls	Dec. 31, 2023 ft³ MMBbls	Dec. 31, 2022 ft³ MMBbls
Proved developed and undeveloped oil reserves:
Proved developed reserves	418.9	418.9	436.2	425.5	436.0
Proved undeveloped reserves	311.1	311.1	292.8	314.0	279.4
Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		729.0	739.5	715.4
Revisions of previous estimates		26.0	14.3	(13.3)
Improved recovery			11.3	0.4
Extensions and discoveries		43.0	31.4	112.6
Purchases of properties		4.3
Sale of properties		(3.4)		(5.2)
Production		(68.9)	(67.5)	(70.4)
Proved developed and undeveloped reserves, ending balance		730.0	729.0	739.5
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		275.1	275.8	303.6
Revisions of previous estimates		20.2	6.6	(10.8)
Improved recovery			10.7	0.4
Extensions and discoveries		5.7	16.6	22.5
Purchases of properties		3.5
Sale of properties		(1.8)		(2.0)
Production		(34.0)	(34.6)	(37.9)
Proved developed and undeveloped reserves, ending balance		268.7	275.1	275.8
Proved developed reserves	173.1	173.1	184.7	186.3	209.0
Proved undeveloped reserves	95.6	95.6	90.4	89.5	94.6
Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		38.6	37.6	41.7
Revisions of previous estimates		1.4	1.2	(1.4)
Improved recovery			0.4
Extensions and discoveries		1.1	2.9	2.0
Purchases of properties		0.4
Sale of properties		(0.8)		(0.6)
Production		(4.0)	(3.5)	(4.1)
Proved developed and undeveloped reserves, ending balance		36.7	38.6	37.6
Proved developed reserves	21.7	21.7	24.1	25.9	29.7
Proved undeveloped reserves	15.0	15.0	14.5	11.7	12.0
Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³	2,491.8		2,556.2	2,219.9
Revisions of previous estimates \| ft³	26.7		39.1	(6.9)
Improved recovery \| ft³			1.2
Extensions and discoveries \| ft³	217.2		71.4	528.9
Purchases of properties \| ft³	2.4
Sale of properties \| ft³	(5.1)			(15.6)
Production \| ft³	(185.3)		(176.1)	(170.1)
Proved developed and undeveloped reserves, ending balance \| ft³	2,547.7		2,491.8	2,556.2
Proved developed reserves \| ft³	1,345.1	1,345.1	1,364.2	1,279.3	1,183.1
Proved undeveloped reserves \| ft³	1,202.6	1,202.6	1,127.6	1,276.9	1,036.8
MP Gulf of Mexico LLC
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance		15.0
Proved developed reserves	13.1	13.1
Proved undeveloped reserves	1.9	1.9
MP Gulf of Mexico LLC \| Net crude oil and condensate revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance		13.9
Proved developed reserves	12.1	12.1
Proved undeveloped reserves	1.8	1.8
MP Gulf of Mexico LLC \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance	1.7	0.4
Proved developed reserves	0.4	0.4
MP Gulf of Mexico LLC \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, ending balance \| ft³	4.2
Proved developed reserves \| ft³	3.9	3.9
Proved undeveloped reserves \| ft³	0.3	0.3
United States
Proved developed and undeveloped oil reserves:
Proved developed reserves	197.8	197.8	218.9	223.2	264.2
Proved undeveloped reserves	94.1	94.1	88.5	87.9	92.8
United States \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		307.4	311.1	357.0
Revisions of previous estimates		18.0	8.1	(13.3)
Improved recovery			11.3	0.0
Extensions and discoveries		4.9	16.0	12.7
Purchases of properties		4.3
Sale of properties		(3.4)		0.0
Production		(39.3)	(39.1)	(45.3)
Proved developed and undeveloped reserves, ending balance		291.9	307.4	311.1
United States \| 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		225.2	228.0	263.6
Revisions of previous estimates		18.2	6.6	(8.9)
Improved recovery			10.7	0.0
Extensions and discoveries		3.4	10.7	8.9
Purchases of properties		3.5
Sale of properties		(1.8)		0.0
Production		(30.3)	(30.8)	(35.6)
Proved developed and undeveloped reserves, ending balance		218.2	225.2	228.0
Proved developed reserves	150.8	150.8	164.1	163.7	194.4
Proved undeveloped reserves	67.4	67.4	61.1	64.3	69.2
United States \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		34.1	34.3	37.6
Revisions of previous estimates		1.2	0.3	(1.2)
Improved recovery			0.4
Extensions and discoveries		0.7	2.4	1.7
Purchases of properties		0.4
Sale of properties		(0.8)		0.0
Production		(3.8)	(3.3)	(3.8)
Proved developed and undeveloped reserves, ending balance	54.2	31.8	34.1	34.3
Proved developed reserves	19.2	19.2	21.9	24.1	27.4
Proved undeveloped reserves	12.6	12.6	12.2	10.2	10.2
United States \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³	288.9		293.1	334.9
Revisions of previous estimates \| ft³	(8.7)		7.7	(19.0)
Improved recovery \| ft³			1.2
Extensions and discoveries \| ft³	4.7		17.0	12.3
Purchases of properties \| ft³	2.4
Sale of properties \| ft³	(5.1)			0.0
Production \| ft³	(31.0)		(30.1)	(35.1)
Proved developed and undeveloped reserves, ending balance \| ft³	251.2		288.9	293.1
Proved developed reserves \| ft³	166.4	166.4	196.8	212.4	254.1
Proved undeveloped reserves \| ft³	84.8	84.8	92.1	80.7	80.8
Canada
Proved developed and undeveloped oil reserves:
Proved developed reserves	220.9	220.9	217.1	202.0	171.3
Proved undeveloped reserves	203.7	203.7	191.8	213.5	186.5
Canada \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		408.9	415.5	357.8
Revisions of previous estimates		7.1	6.3	0.2
Improved recovery			0.0	0.4
Extensions and discoveries		38.1	15.4	87.3
Purchases of properties		0.0
Sale of properties		0.0		(5.2)
Production		(29.5)	(28.3)	(25.0)
Proved developed and undeveloped reserves, ending balance		424.6	408.9	415.5
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		37.7	35.4	39.5
Revisions of previous estimates		1.8	0.1	(1.8)
Improved recovery			0.0	0.4
Extensions and discoveries		2.3	5.9	1.5
Purchases of properties		0.0
Sale of properties		0.0		(2.0)
Production		(3.6)	(3.7)	(2.2)
Proved developed and undeveloped reserves, ending balance		38.2	37.7	35.4
Proved developed reserves	22.1	22.1	20.4	22.3	14.2
Proved undeveloped reserves	16.1	16.1	17.3	13.1	25.3
Canada \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		4.5	3.3	4.1
Revisions of previous estimates		0.2	0.9	(0.2)
Improved recovery			0.0
Extensions and discoveries		0.4	0.5	0.3
Purchases of properties		0.0
Sale of properties		0.0		(0.6)
Production		(0.2)	(0.2)	(0.3)
Proved developed and undeveloped reserves, ending balance	35.1	4.9	4.5	3.3
Proved developed reserves	2.5	2.5	2.2	1.8	2.3
Proved undeveloped reserves	2.4	2.4	2.3	1.5	1.8
Canada \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance \| ft³	2,199.9		2,260.1	1,884.8
Revisions of previous estimates \| ft³	30.8		31.4	12.1
Improved recovery \| ft³			0.0
Extensions and discoveries \| ft³	212.5		54.4	513.8
Purchases of properties \| ft³	0.0
Sale of properties \| ft³	0.0			(15.6)
Production \| ft³	(154.3)		(146.0)	(135.0)
Proved developed and undeveloped reserves, ending balance \| ft³	2,288.9		2,199.9	2,260.1
Proved developed reserves \| ft³	1,178.5	1,178.5	1,167.2	1,066.7	928.8
Proved undeveloped reserves \| ft³	1,110.4	1,110.4	1,032.7	1,193.4	956.0
Other
Proved developed and undeveloped oil reserves:
Proved developed reserves	0.2	0.2	0.2	0.3	0.5
Proved undeveloped reserves	13.3	13.3	12.5	12.6	0.1
Other \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, beginning balance		12.7	12.9	0.6
Revisions of previous estimates		0.9	(0.1)	(0.2)
Improved recovery			0.0	0.0
Extensions and discoveries		0.0	0.0	12.6
Purchases of properties		0.0
Sale of properties		0.0		0.0
Production		(0.1)	(0.1)	(0.1)
Proved developed and undeveloped reserves, ending balance		13.5	12.7	12.9
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		12.2	12.4	0.5
Revisions of previous estimates		0.2	(0.1)	(0.1)
Improved recovery			0.0	0.0
Extensions and discoveries		0.0	0.0	12.1
Purchases of properties		0.0
Sale of properties		0.0		0.0
Production		(0.1)	(0.1)	(0.1)
Proved developed and undeveloped reserves, ending balance		12.3	12.2	12.4
Proved developed reserves	0.2	0.2	0.2	0.3	0.4
Proved undeveloped reserves	12.1	12.1	12.0	12.1	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	0.0	0.0
Revisions of previous estimates		0.0	0.0	0.0
Improved recovery			0.0
Extensions and discoveries		0.0	0.0	0.0
Purchases of properties		0.0
Sale of properties		0.0		0.0
Production		0.0	0.0	0.0
Proved developed and undeveloped reserves, ending balance	7.4	0.0	0.0	0.0
Proved developed reserves	0.0	0.0	0.0	0.0	0.0
Proved undeveloped reserves	0.0	0.0	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		3.0	0.2
Revisions of previous estimates \| ft³	4.6		0.0	0.0
Improved recovery \| ft³			0.0
Extensions and discoveries \| ft³	0.0		0.0	2.8
Purchases of properties \| ft³	0.0
Sale of properties \| ft³	0.0			0.0
Production \| ft³	0.0		0.0	0.0
Proved developed and undeveloped reserves, ending balance \| ft³	7.6		3.0	3.0
Proved developed reserves \| ft³	0.2	0.2	0.2	0.2	0.2
Proved undeveloped reserves \| ft³	7.4	7.4	2.8	2.8	0.0

Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2025

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 2025 and 2024 the Company entered into natural gas swap contracts. 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.

During 2025, the Company entered into natural gas swap contracts that matured by December 31, 2025. The Company did not have any outstanding natural gas derivative contracts at year end. Volumes per day and the weighted average prices for these contracts were as follows:

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural gas

3.58

2/1/2025

6/30/2025

Fixed price derivative swap

United States

Natural gas

3.65

7/1/2025

9/30/2025

Fixed price derivative swap

United States

Natural gas

3.74

10/1/2025

12/31/2025

During 2024, the Company entered into natural gas swap contracts that were effective in 2025. At December 31, 2024, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows:

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural gas

3.20

1/1/2025

1/31/2025

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, 2025 and 2024.

At December 31, 2025 and 2024, 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 Sheets Location	2025		2024

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	Statements of Operations Locations	2025		2024		2023
Commodity swaps	Gain (loss) on derivative instruments	$	5,927	$	(1,707)	$	—

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.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 182
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-182

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 185
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+ Details

Leases - Schedule of Maturity of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Operating Leases
2026	$ 315,609
2027	146,130
2028	63,009
2029	60,214
2030	58,445
Remaining	366,321
Total future minimum lease payments	1,009,728
Less imputed interest	(193,121)
Lease obligation	816,607
Finance Leases
2026	3,302
2027	3,302
2028	3,302
2029	2,491
2030	1,885
Remaining	774
Total future minimum lease payments	15,056
Less imputed interest	(2,402)
Present value of lease liabilities	12,654	$ 4,877
Total
2026	318,911
2027	149,432
2028	66,311
2029	62,705
2030	60,330
Remaining	367,095
Total future minimum lease payments	1,024,784
Less imputed interest	(195,523)
Present value of lease liabilities	$ 829,261

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, 2025	Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plan	$ 22,205	$ 19,469
Derivative Liability, Statement of Financial Position [Extensible Enumeration]
Commodity swaps	0	$ 1,707
Liabilities	22,205	21,176
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plan	22,205	19,469
Commodity swaps	0	0
Liabilities	22,205	19,469
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plan	0	0
Commodity swaps	0	1,707
Liabilities	0	1,707
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plan	0	0
Commodity swaps	0	0
Liabilities	$ 0	$ 0

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

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+ Details

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Pretax Impairment	$ 28,400,000	$ 34,500,000	$ 115,002,000	$ 62,909,000	$ 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		157,399,000	63,410,000
Total Pretax Impairment			115,002,000	62,909,000
Level 1 \| United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	0		0	0
Level 2 \| United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	0		0	0
Level 3 \| United States - Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	$ 501,000		$ 42,397,000	$ 501,000

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2025

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, 2025					December 31, 2024
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production ¹	$	23,042,373	$	8,099,291	2	$	21,716,358	$	8,021,620	2
Corporate and other	162,122		37,055			149,834		33,033
Property, plant and equipment	$	23,204,495	$	8,136,346		$	21,866,192	$	8,054,653
¹ Includes unproved mineral rights as follows:	$	229,759	$	99,729		$	283,015	$	151,341

2 Includes $12,050 in 2025 and $13,335 in 2024 related to administrative assets and support equipment.

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)	2025		2024		2023
Beginning balance at January 1	$	72,055	$	49,118	$	171,860
Additions pending the determination of proved reserves	119,766		49,408		48
Reclassifications to proved properties based on the determination of proved reserves	—		—		(82,185)

Capitalized exploration well costs charged to expense	—		(26,471)		(40,605)
Ending balance at December 31	$	191,821	$	72,055	$	49,118

Schedule of Aging of Capitalized Exploratory Well Costs

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well.


	2025			2024			2023
(Thousands of dollars)	Amount		No. of Wells		Amount		No. of Wells	Amount		No. of Wells
Aging of capitalized well costs
Zero to one year	$	28,384	2		$	49,790	5	$	—	0
One to two years	140,959		6		—		—	—		0
Two to three years	—		—		—		—	2,698		1
Three years or more	22,478		3		22,265		3	46,420		3
	$	191,821	11		$	72,055	8	$	49,118	4

Leases (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Schedule of Lease Expenses, Term and Discount Rate

Expenses related to finance and operating leases (both short-term and long-term) included in the Consolidated Financial Statements are as follows.


		Year Ended December 31,
(Thousands of dollars)	Financial Statements Category	2025		2024
Operating lease 1, 2	Lease operating expenses	$	342,520	$	411,303
Operating lease 2	Transportation, gathering and processing	8,308		16,117
Operating lease 2	Selling and general expenses	10,405		10,990
Operating lease 2	Other operating expense	467		6,622
Operating lease 2	Exploration expenses	14,335		38,974

Operating lease 2	Property, plant and equipment	175,400		277,170
Operating lease 2	Asset retirement obligations	85,690		10
Finance lease
Amortization of asset	Depreciation, depletion and amortization	1,026		855
Interest on lease liabilities	Interest expense, net	229		193
Sublease income	Other income	(240)		(1,143)
Net lease expense		$	638,140	$	761,091


(Thousands of dollars)	Year Ended December 31,
Financial Statements Category	2025		2024
Lease operating expenses	$	159,746	$	236,402
Transportation, gathering and processing	8,308		12,993
Selling and general expenses	1,918		772
Other operating expense	16		6,230
Exploration expenses	13,211		38,500

Property, plant and equipment	96,909		97,104
Asset retirement obligations	65,418		10
Total short-term lease expense	$	345,526	$	392,011

Schedule of Maturity of Operating Leases

Maturity of Lease Liabilities


(Thousands of dollars)	Operating Leases		Finance Leases		Total
2026	$	315,609	$	3,302	$	318,911
2027	146,130		3,302		149,432
2028	63,009		3,302		66,311
2029	60,214		2,491		62,705
2030	58,445		1,885		60,330
Remaining	366,321		774		367,095
Total future minimum lease payments	1,009,728		15,056		1,024,784
Less imputed interest	(193,121)		(2,402)		(195,523)
Present value of lease liabilities 1	$	816,607	$	12,654	$	829,261

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
2026	$	315,609	$	3,302	$	318,911
2027	146,130		3,302		149,432
2028	63,009		3,302		66,311
2029	60,214		2,491		62,705
2030	58,445		1,885		60,330
Remaining	366,321		774		367,095
Total future minimum lease payments	1,009,728		15,056		1,024,784
Less imputed interest	(193,121)		(2,402)		(195,523)
Present value of lease liabilities 1	$	816,607	$	12,654	$	829,261

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, 2025		December 31, 2024
Weighted average remaining lease term:
Operating leases	7 years		8 years
Finance leases	5 years		6 years
Weighted average discount rate:
Operating leases	5.5	%	5.7	%
Finance leases	5.4	%	4.9	%

Other Information


	Year Ended December 31,
(Thousands of dollars)	2025		2024
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	258,564	$	328,847
Operating cash flows from finance leases	339		311
Financing cash flows from finance leases	1,238		665
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases ¹	$	247,566	$	349,312
Finance leases 2	8,845		1,749

2 For the year ended December 31, 2025, right-of-use assets obtained in exchange for finance lease liabilities primarily included $8.8 million related to computing equipment in the U.S.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
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

Business Segments - Narrative (Details) - USD ($)	12 Months Ended
Business Segments - Narrative (Details) - USD ($)	Dec. 31, 2025	Dec. 31, 2024
Segment Reporting [Abstract]
Number Of Reportable Segments Not Disclosed Flag	true
Assets held-for-sale	$ 0	$ 0

Inventories

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Inventories

Note E – Inventories

Inventories consisted of the following for the respective periods presented.


	December 31,
(Thousands of dollars)	2025		2024
Unsold crude oil	$	17,560	$	18,745
Materials and supplies	39,724		36,113
Inventories	$	57,284	$	54,858

Property, Plant and Equipment - Narrative (Details)		1 Months Ended	3 Months Ended					12 Months Ended
Property, Plant and Equipment - Narrative (Details)	Jul. 01, 2025 USD ($)	Sep. 30, 2025 USD ($)	Dec. 31, 2025 USD ($) foot	Sep. 30, 2025 USD ($)	Mar. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Mar. 31, 2024 USD ($)	Dec. 31, 2025 USD ($) foot well	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Feb. 25, 2026 foot	Dec. 31, 2022 USD ($)
Property, Plant and Equipment [Line Items]
Amount			$ 191,821,000			$ 72,055,000		$ 191,821,000	$ 72,055,000	$ 49,118,000		$ 171,860,000
Additions pending the determination of proved reserves								119,766,000	49,408,000	48,000
Reclassifications to proved properties based on the determination of proved reserves								0	0	(82,185,000)
Capitalized exploration well costs charged to expense								0	(26,471,000)	(40,605,000)
Well costs incurred and expensed								30,100,000	46,700,000	129,200,000
Exploratory well costs capitalized more than one year			163,400,000					163,400,000
Impairment of assets						$ 28,400,000	$ 34,500,000	115,002,000	62,909,000	0
Discontinued Operations, Disposed of by Sale \| Brunei CA-2
Property, Plant and Equipment [Line Items]
Cash received from divestiture			$ 12,500,000					$ 12,500,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]			Gain on sale of assets and other operating income
Gain (loss) on sale of assets			$ 4,000,000.0
Gain on write-down			$ 6,000,000.0
Discontinued Operations, Disposed of by Sale \| Ralph And Saylee Area Of Tilden West
Property, Plant and Equipment [Line Items]
Gain (loss) on sale of assets		$ 0
Consideration adjustment sale price		$ 8,200,000		$ 8,200,000
BW Pioneer Floating Production Storage And Offloading Vessel (FPSO)
Property, Plant and Equipment [Line Items]
Consideration transferred					$ 125,000,000.0
Block CI-502
Property, Plant and Equipment [Line Items]
Number of exploration wells \| well								2
Well costs incurred and expensed								$ 30,000,000.0
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									13,400,000
Walker Ridge 425
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed										82,000,000.0
Atwater Valley 138
Property, Plant and Equipment [Line Items]
Well costs incurred and expensed										$ 47,200,000
Subsequent Event \| Banjo
Property, Plant and Equipment [Line Items]
Net payable area \| foot											50
Subsequent Event \| Cello
Property, Plant and Equipment [Line Items]
Net payable area \| foot											30
Vietnam
Property, Plant and Equipment [Line Items]
Net oil pay, feet \| foot			106					106
Exploratory well costs capitalized more than one year			$ 91,500,000					$ 91,500,000
Gulf of America
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year			64,600,000					64,600,000
Canada
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year			4,600,000					4,600,000
Brunei
Property, Plant and Equipment [Line Items]
Exploratory well costs capitalized more than one year			$ 2,700,000					2,700,000
Eagle Ford Shale
Property, Plant and Equipment [Line Items]
Payments to acquire additional working interests	$ 23,000,000.0
United States Offshore
Property, Plant and Equipment [Line Items]
Impairment of assets								$ 115,002,000	$ 62,909,000
Impairment of assets excluding NCI				$ 92,000,000.0

Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Price Risk Derivatives

The Company did not have any outstanding natural gas derivative contracts at year end. Volumes per day and the weighted average prices for these contracts were as follows:

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural gas

3.58

2/1/2025

6/30/2025

Fixed price derivative swap

United States

Natural gas

3.65

7/1/2025

9/30/2025

Fixed price derivative swap

United States

Natural gas

3.74

10/1/2025

12/31/2025

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural gas

3.20

1/1/2025

1/31/2025

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

At December 31, 2025 and 2024, 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 Sheets Location	2025		2024

Commodity swaps	Accounts payable	$	—	(1,707)

Schedule of Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments


		Gain (Loss)
(Thousands of dollars)		Year Ended December 31,
Type of Derivative Contract	Statements of Operations Locations	2025		2024		2023
Commodity swaps	Gain (loss) on derivative instruments	$	5,927	$	(1,707)	$	—

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Line Items]
Increase (decrease) in deferred tax asset valuation allowance	$ 8,300
U. S. net operating loss	224,956	$ 289,594
Earnings expected to be repatriated in next fiscal year	100,000
Deferred tax liability, undistributed foreign earnings	5,000	5,000
Undistributed foreign earnings	1,600,000
Other recorded liabilities for interest and penalties	300	$ 300	$ 300
Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 1,100,000

Leases - Schedule of Lease Related Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Amortization of asset	$ 1,026	$ 855
Interest on lease liabilities	229	193
Sublease income	(240)	(1,143)
Net lease expense	638,140	761,091
Variable lease expenses primarily related to additional volumes processed at natural gas processing plant	34,600	42,300
Short-term lease cost	345,526	392,011
Lease operating expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	342,520	411,303
Short-term lease cost	159,746	236,402
Transportation, gathering and processing
Lessee, Lease, Description [Line Items]
Operating lease cost	8,308	16,117
Short-term lease cost	8,308	12,993
Selling and general expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	10,405	10,990
Short-term lease cost	1,918	772
Other operating expense
Lessee, Lease, Description [Line Items]
Operating lease cost	467	6,622
Short-term lease cost	16	6,230
Exploration expenses
Lessee, Lease, Description [Line Items]
Operating lease cost	14,335	38,974
Short-term lease cost	13,211	38,500
Property, plant and equipment
Lessee, Lease, Description [Line Items]
Operating lease cost	175,400	277,170
Short-term lease cost	96,909	97,104
Asset retirement obligations
Lessee, Lease, Description [Line Items]
Operating lease cost	85,690	10
Short-term lease cost	$ 65,418	$ 10

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Accumulated depreciation, depletion and amortization	$ 15,068,149	$ 13,811,539
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)	$ 1.00	$ 1.00
Common stock, authorized shares (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	195,100,628	195,100,628

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

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

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, 2025	Dec. 31, 2024
Funded plan \| Qualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 0	$ 497,947
Accumulated Benefit Obligations	0	489,225
Fair Value of Plan Assets	0	477,983
Unfunded plan \| Other postretirement plans
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	63,399	54,994
Accumulated Benefit Obligations	63,399	54,994
Fair Value of Plan Assets	0	0
Unfunded plan \| Nonqualified plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	147,339	145,058
Accumulated Benefit Obligations	145,545	143,859
Fair Value of Plan Assets	$ 0	$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

Property, Plant And Equipment - Schedule of Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Capitalized Exploratory Well Cost [Roll Forward]
Beginning balance at January 1	$ 72,055	$ 49,118	$ 171,860
Additions pending the determination of proved reserves	119,766	49,408	48
Reclassifications to proved properties based on the determination of proved reserves	0	0	(82,185)
Capitalized exploration well costs charged to expense	0	(26,471)	(40,605)
Ending balance at December 31	$ 191,821	$ 72,055	$ 49,118

Incentive Plans - Schedule of Changes in Restricted Stock Units Outstanding (Details) - Restricted Stock and Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year (in shares)	1,558,600	1,219,584	1,227,792
Granted (in shares)	559,284	741,228	556,100
Vested and issued (in shares)	(360,281)	(330,444)	(517,047)
Forfeited (in shares)	(95,951)	(71,768)	(47,261)
Outstanding at end of year (in shares)	1,661,652	1,558,600	1,219,584

Employee and Retiree Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2025

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 Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Change in benefit obligation
Obligation at January 1	$	655,324	$	699,151	$	54,994	$	63,808
Service cost	7,094		7,042		382		436
Interest cost	33,798		33,554		3,261		2,923
Participant contributions	—		—		2,762		2,730
Actuarial (gain) loss 1	1,175		(35,417)		17,681		825
Medicare Part D subsidy	—		—		383		358
Exchange rate changes	8,010		(3,263)		9		(14)
Benefits paid	(45,907)		(45,743)		(16,073)		(16,072)




Obligation at December 31	659,494		655,324		63,399		54,994
Change in plan assets
Fair value of plan assets at January 1	492,120		477,809		—		—
Actual return on plan assets	48,285		27,317		—		—
Employer contributions	25,067		35,477		12,928		12,984
Participant contributions	—		—		2,762		2,730
Medicare Part D subsidy	—		—		383		358
Exchange rate changes	7,514		(2,740)		—		—
Benefits paid	(45,907)		(45,743)		(16,073)		(16,072)

Fair value of plan assets at December 31	527,079		492,120		—		—
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	14,925		1,819		—		—
Other accrued liabilities	(10,354)		(10,617)		(4,663)		(4,237)
Deferred credits and other liabilities	(136,986)		(154,406)		(58,736)		(50,757)
Fund Status and net plan liability recognized at December 31	$	(132,415)	$	(163,204)	$	(63,399)	$	(54,994)

The preceding tables in this note include the following amounts related to foreign benefit plans.


	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Benefit obligation at December 31	$	109,883	$	115,428	$	90	$	106
Fair value of plan assets at December 31	110,280		103,445		—		—
Net plan liabilities recognized	397		(11,983)		(90)		(106)
Net periodic benefit (credit) expense	2,131		1,480		(35)		(44)

Schedule of Amounts Included in Accumulated Other Comprehensive Loss Not Recognized in Net Periodic Benefit Expense


(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
Net actuarial gain (loss)	$	(148,280)	$	18,862
Prior service (credit) cost	(16,320)		2,873
	$	(164,600)	$	21,735

Schedule of Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets


	Projected Benefit Obligations				Accumulated Benefit Obligations				Fair Value of Plan Assets
(Thousands of dollars)	2025		2024		2025		2024		2025		2024
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	—	$	497,947	$	—	$	489,225	$	—	$	477,983
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets	147,339		145,058		145,545		143,859		—		—
Unfunded other postretirement plans	63,399		54,994		63,399		54,994		—		—

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 Postretirement Benefits
(Thousands of dollars)	2025		2024		2023		2025		2024		2023
Service cost	$	7,094	$	7,042	$	6,542	$	382	$	436	$	495
Interest cost	33,798		33,554		34,140		3,261		2,923		3,241
Expected return on plan assets	(35,511)		(33,427)		(32,839)		—		—		—

Amortization of prior service cost (credit)	1,967		2,316		620		(532)		(532)		(532)

Recognized actuarial (gain) loss	7,262		9,438		9,776		(3,182)		(3,586)		(3,512)
Net periodic benefit cost (credit)	14,610		18,923		18,239		(71)		(759)		(308)

Other pension costs	276		251		219		—		—		—
Total net periodic benefit cost (credit)	$	14,886	$	19,174	$	18,458	$	(71)	$	(759)	$	(308)

Schedule of Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense


	Benefit Obligations								Net Periodic Benefit Expense
	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,				Year				Year
	2025		2024		2025		2024		2025		2024		2025		2024
Discount rate on obligation, interest cost and service cost	5.41	%	5.58	%	5.48	%	5.65	%	5.54	%	5.17	%	5.66	%	5.15	%
Rate of compensation increase	3.50	%	3.38	%	—		—		3.50	%	3.50	%	—		—
Cash balance interest credit rate	3.70	%	3.20	%	—		—		—		—		—		—
Expected return on plan assets	—		—		—		—		7.29	%	7.19	%	—		—

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 Benefits		Other Postretirement Benefits
2026	$	49,819	$	4,663
2027	51,276		4,710
2028	51,786		4,872
2029	51,646		4,772
2030	53,230		4,752
2031-2035	260,581		23,671

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,
	2025		2024
Equity securities	45.2	%	57.3	%
Fixed income securities	42.7	%	36.2	%
Alternatives	7.4	%	3.7	%
Cash equivalents	4.7	%	2.8	%
	100.0	%	100.0	%

Schedule of Fair Value Measurements of Retirement Plan Assets

At December 31, 2025, 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, 2025		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	83,956	$	73,999	$	—	$	9,957
U.S. small/midcap	56,699		56,699		—		—
Other alternative strategies	21,032		—		—		21,032
International equity	27,772		27,772		—		—
Emerging market equity	13,518		13,518		—		—
Fixed income securities:
U.S. fixed income	186,995		119,205		67,790		—
International commingled trust fund	7,047		—		7,047		—

Cash and equivalents	19,779		19,779		—		—
Total Domestic Plans	416,798		310,972		74,837		30,989
Foreign Plans
Equity securities funds	13,946		—		13,946		—
Fixed income securities funds	30,986		—		30,986		—
Diversified pooled fund	42,124		—		42,124		—
Other	18,454		—		532		17,922
Cash and equivalents	4,771		—		4,771		—
Total Foreign Plans	110,281		—		92,359		17,922
Total	$	527,079	$	310,972	$	167,196	$	48,911

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, 2024		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	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

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 Alternative Strategies
Total at December 31, 2023	$	24,454
Actual return (loss) on plan assets 1:
Relating to assets held at the reporting date	(3,574)

Purchases, sales and settlements	(2,865)
Total at December 31, 2024	18,015
Actual return on plan assets 1:
Relating to assets held at the reporting date	2,394

Purchases, sales and settlements	28,502
Total at December 31, 2025	$	48,911

1 Gains and losses on Level 3 plan assets are recognized in the Consolidated Statements of Comprehensive Income (Loss) under the caption "Retirement and postretirement benefit plans.”

Common Stock Issued and Outstanding - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity [Abstract]
Stock repurchase program, authorized amount	$ 1,100,000,000
Treasury shares purchased (in shares)	3,613,450	8,008,786	3,411,158
Repurchase of common stock	$ 100,000,000.0
Treasury stock, value, acquired, cost method, net	100,800,000
Stock repurchase program, remaining amount	$ 550,100,000

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025		2024
Balance at beginning of year	$	1,008,884	$	914,763
Accretion	57,730		52,511
Liabilities incurred	20,744		25,619

Revisions of previous estimates	(12,094)		29,279
Liabilities settled	(70,829)		(1,898)


Changes due to translation of foreign currencies	8,432		(11,390)
Balance at end of period	1,012,867		1,008,884
Current portion of liability	(41,959)		(48,080)
Non-current portion of liability	$	970,908	$	960,804

Business Segments (Tables)

12 Months Ended

Dec. 31, 2025

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.


	2025		2024		2023
Chevron Corporation	19	%	13	%	16	%
ExxonMobil Corporation	12	%	20	%	27	%
Phillips 66	N/A		10	%	N/A

Schedule of Segment Information


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, and Discontinued Operations		Consolidated Total
Year ended December 31, 2025
Revenue from production	$	2,153.9	$	530.2	$	5.7	$	2,689.8	$	—	$	2,689.8

Gain on sales of assets and other operating income	5.9		1.7		10.0		17.6		13.8		31.4
Total revenues and other income	2,159.8		531.9		15.7		2,707.4		13.8		2,721.2
Lease operating expenses
Lease operating expenses and taxes other than income	391.4		178.9		2.5		572.8		—		572.8
Repair and maintenance	60.8		5.1		—		65.9		—		65.9
Workovers	124.9		1.6		—		126.5		—		126.5
Total lease operating expenses	577.1		185.6		2.5		765.2		—		765.2
Severance and ad valorem taxes	37.7		1.5		—		39.2		—		39.2
Transportation, gathering and processing	107.0		92.7		—		199.7		—		199.7

Selling and general expenses	13.7		23.7		8.8		46.2		91.1		137.3
Exploration expenses
Geological and geophysical	27.2		0.1		8.7		36.0		—		36.0
Dry holes and previously suspended exploration costs	(0.9)		—		31.0		30.1		—		30.1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	14.7		0.3		30.6		45.6		—		45.6
Total exploration expenses	41.0		0.4		70.3		111.7		—		111.7
Depreciation, depletion and amortization	822.1		144.8		2.5		969.4		8.4		977.8
Impairment of assets	115.0		—		—		115.0		—		115.0
Accretion of asset retirement obligations	46.6		10.3		0.7		57.6		0.1		57.7

Other operating expenses (income)	10.8		1.8		(0.9)		11.7		2.2		13.9


Interest income	(1.7)		—		—		(1.7)		(11.8)		(13.5)
Interest expense, net of capitalization	0.1		0.1		0.2		0.4		95.7		96.1
Income tax expense (benefit)
Current income tax expense (benefit)	0.8		10.6		0.3		11.7		(1.8)		9.9
Deferred income tax expense (benefit)	76.9		4.0		(2.4)		78.5		(43.8)		34.7
Total income tax expense (benefit)	77.7		14.6		(2.1)		90.2		(45.6)		44.6
Other segment costs	4.2		1.6		0.3		6.1		31.6		37.7
Segment income (loss) - including NCI 1	$	308.5	$	54.8	$	(66.6)	$	296.7	$	(157.9)	$	138.8

Additions to property, plant, equipment	$	763.5	$	152.5	$	180.9	$	1,096.9	$	21.2	$	1,118.1
Total assets at year-end	6,771.3		2,000.0		598.1		9,369.4		463.2		9,832.6

1 Includes results attributable to the noncontrolling interest in MP GOM.


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, and Discontinued Operations		Consolidated Total
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
Total revenues and other income	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 (income)	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 (benefit)
Current income tax expense (benefit)	1.5		3.2		0.2		4.9		0.9		5.8
Deferred income tax expense (benefit)	123.8		8.8		(31.2)		101.4		(28.9)		72.5
Total income tax expense (benefit)	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 the noncontrolling interest in MP GOM.


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, and Discontinued Operations		Consolidated Total
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
Total revenues and other income	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 (income)	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 (benefit)
Current income tax expense (benefit)	3.1		3.7		0.6		7.4		8.8		16.2
Deferred income tax expense (benefit)	229.6		7.5		(6.7)		230.4		(50.6)		179.8
Total income tax expense (benefit)	232.7		11.2		(6.1)		237.8		(41.8)		196.0
Other segment costs	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 the noncontrolling interest in MP GOM.


Geographic Information	Certain long-lived assets at December 31 1
(Millions of dollars)	United States		Canada		Other		Total
2025	$	6,236.8	$	1,460.6	$	438.9	$	8,136.3
2024	6,415.9		1,389.5		249.2		8,054.6
2023	6,555.0		1,497.3		172.8		8,225.1

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.

Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2025

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)	2025		2024		2023
Net crude oil and condensate revenue
United States - Onshore	$	617,358	$	586,584	$	676,139
United States - Offshore 1	1,355,527		1,777,723		2,072,353
Canada - Onshore	61,715		70,855		78,088
Canada - Offshore	187,030		193,961		78,650
Other	5,713		6,537		11,022
Total crude oil and condensate revenue	2,227,343		2,635,660		2,916,252
Net natural gas liquids revenue
United States - Onshore	41,518		32,853		33,178
United States - Offshore 1	33,029		38,858		47,434
Canada - Onshore	5,626		7,454		8,914
Total natural gas liquids revenue	80,173		79,165		89,526
Net natural gas revenue
United States - Onshore	35,524		17,443		21,346
United States - Offshore 1	70,968		50,329		71,332
Canada - Onshore	275,837		232,259		278,183
Total natural gas revenue	382,329		300,031		370,861
Revenue from production	2,689,845		3,014,856		3,376,639
Sales of purchased natural gas 2

Canada - Onshore	—		3,742		72,215
Total sales of purchased natural gas	—		3,742		72,215
Total revenue from sales to customers	2,689,845		3,018,598		3,448,854
Gain (loss) on derivative instruments	5,927		(1,707)		—
Gain on sale of assets and other operating income	23,051		11,583		11,293
Total revenues and other income	$	2,718,823	$	3,028,474	$	3,460,147

1 Includes revenue attributable to the noncontrolling interest in MP GOM.

Schedule of Current Long-Term Contracts Outstanding

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Natural Gas and NGLs

Q2 2030

Deliveries from dedicated acreage in Eagle Ford Shale

As produced

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at USD index pricing

30 MMCF/D

Canada

Natural Gas

Q4 2028

Contracts to sell natural gas at USD index pricing

10 MMCF/D

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at CAD fixed pricing

50 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at CAD fixed pricing

9 MMCF/D

Canada

NGLs

Q4 2026

Contracts to sell NGLs at CAD index pricing

As produced

Employee and Retiree Benefit Plans - Schedule of Benefit Payments Expected to be Paid in Future Years (Details) $ in Thousands	Dec. 31, 2025 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	$ 49,819
2027	51,276
2028	51,786
2029	51,646
2030	53,230
2031-2035	260,581
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	4,663
2027	4,710
2028	4,872
2029	4,772
2030	4,752
2031-2035	$ 23,671

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

Business Segments

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Business Segments

Note S – Business Segments

Murphy’s reportable segments are organized into geographic areas of operations. The Company’s E&P 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. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the CODM.

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.


	2025		2024		2023
Chevron Corporation	19	%	13	%	16	%
ExxonMobil Corporation	12	%	20	%	27	%
Phillips 66	N/A		10	%	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, 2025 and 2024. The Company has accounted for its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations for all periods presented.

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 includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals.

“Other segment costs (income)” 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 (income)” 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 E&P		Corporate, and Discontinued Operations		Consolidated Total
Year ended December 31, 2025
Revenue from production	$	2,153.9	$	530.2	$	5.7	$	2,689.8	$	—	$	2,689.8

Gain on sales of assets and other operating income	5.9		1.7		10.0		17.6		13.8		31.4
Total revenues and other income	2,159.8		531.9		15.7		2,707.4		13.8		2,721.2
Lease operating expenses
Lease operating expenses and taxes other than income	391.4		178.9		2.5		572.8		—		572.8
Repair and maintenance	60.8		5.1		—		65.9		—		65.9
Workovers	124.9		1.6		—		126.5		—		126.5
Total lease operating expenses	577.1		185.6		2.5		765.2		—		765.2
Severance and ad valorem taxes	37.7		1.5		—		39.2		—		39.2
Transportation, gathering and processing	107.0		92.7		—		199.7		—		199.7

Selling and general expenses	13.7		23.7		8.8		46.2		91.1		137.3
Exploration expenses
Geological and geophysical	27.2		0.1		8.7		36.0		—		36.0
Dry holes and previously suspended exploration costs	(0.9)		—		31.0		30.1		—		30.1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	14.7		0.3		30.6		45.6		—		45.6
Total exploration expenses	41.0		0.4		70.3		111.7		—		111.7
Depreciation, depletion and amortization	822.1		144.8		2.5		969.4		8.4		977.8
Impairment of assets	115.0		—		—		115.0		—		115.0
Accretion of asset retirement obligations	46.6		10.3		0.7		57.6		0.1		57.7

Other operating expenses (income)	10.8		1.8		(0.9)		11.7		2.2		13.9


Interest income	(1.7)		—		—		(1.7)		(11.8)		(13.5)
Interest expense, net of capitalization	0.1		0.1		0.2		0.4		95.7		96.1
Income tax expense (benefit)
Current income tax expense (benefit)	0.8		10.6		0.3		11.7		(1.8)		9.9
Deferred income tax expense (benefit)	76.9		4.0		(2.4)		78.5		(43.8)		34.7
Total income tax expense (benefit)	77.7		14.6		(2.1)		90.2		(45.6)		44.6
Other segment costs	4.2		1.6		0.3		6.1		31.6		37.7
Segment income (loss) - including NCI 1	$	308.5	$	54.8	$	(66.6)	$	296.7	$	(157.9)	$	138.8

Additions to property, plant, equipment	$	763.5	$	152.5	$	180.9	$	1,096.9	$	21.2	$	1,118.1
Total assets at year-end	6,771.3		2,000.0		598.1		9,369.4		463.2		9,832.6

1 Includes results attributable to the noncontrolling interest in MP GOM.


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, and Discontinued Operations		Consolidated Total
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
Total revenues and other income	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 (income)	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 (benefit)
Current income tax expense (benefit)	1.5		3.2		0.2		4.9		0.9		5.8
Deferred income tax expense (benefit)	123.8		8.8		(31.2)		101.4		(28.9)		72.5
Total income tax expense (benefit)	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 the noncontrolling interest in MP GOM.


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, and Discontinued Operations		Consolidated Total
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
Total revenues and other income	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 (income)	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 (benefit)
Current income tax expense (benefit)	3.1		3.7		0.6		7.4		8.8		16.2
Deferred income tax expense (benefit)	229.6		7.5		(6.7)		230.4		(50.6)		179.8
Total income tax expense (benefit)	232.7		11.2		(6.1)		237.8		(41.8)		196.0
Other segment costs	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 the noncontrolling interest in MP GOM.


Geographic Information	Certain long-lived assets at December 31 1
(Millions of dollars)	United States		Canada		Other		Total
2025	$	6,236.8	$	1,460.6	$	438.9	$	8,136.3
2024	6,415.9		1,389.5		249.2		8,054.6
2023	6,555.0		1,497.3		172.8		8,225.1

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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+ Details

Incentive Plans - Schedule of Share-Based Plans, Amounts Recognized in the Financial Statements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Compensation charged against income before income tax benefit	$ 50,107	$ 40,831	$ 58,760
Related income tax benefit recognized in income	$ 6,438	$ 5,513	$ 9,330

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, 2025	Dec. 31, 2024	Dec. 31, 2023
Change in plan assets
Beginning balance	$ 492,120
Ending balance	527,079	$ 492,120
Pension Benefits
Change in benefit obligation
Beginning balance	655,324	699,151
Service cost	7,094	7,042	$ 6,542
Interest cost	33,798	33,554	34,140
Participant contributions	0	0
Actuarial (gain) loss	1,175	(35,417)
Medicare Part D subsidy	0	0
Exchange rate changes	8,010	(3,263)
Benefits paid	(45,907)	(45,743)
Ending balance	659,494	655,324	699,151
Change in plan assets
Beginning balance	492,120	477,809
Actual return on plan assets	48,285	27,317
Employer contributions	25,067	35,477
Participant contributions	0	0
Medicare Part D subsidy	0	0
Exchange rate changes	7,514	(2,740)
Benefits paid	(45,907)	(45,743)
Ending balance	527,079	492,120	477,809
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	14,925	1,819
Other accrued liabilities	(10,354)	(10,617)
Deferred credits and other liabilities	(136,986)	(154,406)
Funded status and net plan liability recognized at December 31	(132,415)	(163,204)
Other Postretirement Benefits
Change in benefit obligation
Beginning balance	54,994	63,808
Service cost	382	436	495
Interest cost	3,261	2,923	3,241
Participant contributions	2,762	2,730
Actuarial (gain) loss	17,681	825
Medicare Part D subsidy	383	358
Exchange rate changes	9	(14)
Benefits paid	(16,073)	(16,072)
Ending balance	63,399	54,994	63,808
Change in plan assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	12,928	12,984
Participant contributions	2,762	2,730
Medicare Part D subsidy	383	358
Exchange rate changes	0	0
Benefits paid	(16,073)	(16,072)
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	(4,663)	(4,237)
Deferred credits and other liabilities	(58,736)	(50,757)
Funded status and net plan liability recognized at December 31	$ (63,399)	$ (54,994)

Property, Plant And Equipment - Schedule of Aging of Capitalized Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2025 USD ($) well	Dec. 31, 2024 USD ($) well	Dec. 31, 2023 USD ($) well	Dec. 31, 2022 USD ($)
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount \| $	$ 191,821	$ 72,055	$ 49,118	$ 171,860
No. of Wells (in wells) \| well	11	8	4
Zero to one year
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount \| $	$ 28,384	$ 49,790	$ 0
No. of Wells (in wells) \| well	2	5	0
One to two years
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount \| $	$ 140,959	$ 0	$ 0
No. of Wells (in wells) \| well	6	0	0
Two to three years
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount \| $	$ 0	$ 0	$ 2,698
No. of Wells (in wells) \| well	0	0	1
Three years or more
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Amount \| $	$ 22,478	$ 22,265	$ 46,420
No. of Wells (in wells) \| well	3	3	3

Commitments	12 Months Ended
Commitments	Dec. 31, 2025
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 $132.8 million in 2026, $107.3 million in 2027, $97.6 million in 2028, $66.3 million in 2029 and $45.8 million in 2030. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Commitments for Vietnam in Other Offshore include future operating agreements for production activities. Annual payments for the next five years are $23.6 million in 2026, $23.1 million in 2027, $24.0 million in 2028, $23.9 million in 2029 and $24.2 million in 2030. Commitments for capital expenditures were approximately $551.2 million at December 31, 2025, primarily consisting of $245.3 million for the Gulf of America, $82.6 million for the Eagle Ford Shale, $49.8 million for Canada, $127.5 million for Vietnam, and $45.0 million in for Côte d’Ivoire.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interest	$ 138,799	$ 486,485	$ 723,681
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	73,993	(134,692)	36,598
Retirement and postretirement benefit plans	(148)	27,737	(23,029)
Other comprehensive income (loss)	73,845	(106,955)	13,569
Comprehensive income including noncontrolling interest	212,644	379,530	737,250
Less: Comprehensive income attributable to noncontrolling interest	34,565	79,314	62,122
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY	$ 178,079	$ 300,216	$ 675,128

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income, attributable to parent entity. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income (loss) and other comprehensive income (loss), attributable to noncontrolling interests. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References

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- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax and reclassification adjustments of other comprehensive income (loss).

+ References

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The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

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, 2025	Dec. 31, 2024
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	$ 492,120
Ending balance	527,079	$ 492,120
Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning balance	18,014
Ending balance	48,911	18,014
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	18,015	24,454
Relating to assets held at the reporting date	2,394	(3,574)
Purchases, sales and settlements	28,502	(2,865)
Ending balance	$ 48,911	$ 18,015

- Definition

+ References

+ Details

Subsequent Event (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions		1 Months Ended
	Jan. 23, 2026	Jan. 31, 2026	Jan. 30, 2026	Jan. 28, 2026
Revolving Credit Facility
Subsequent Event [Line Items]
Extinguishment of debt		$ 100.0
Credit facility maximum borrowing capacity		$ 2,000.0	$ 1,350.0
Senior Notes
Subsequent Event [Line Items]
Extinguishment of debt	$ 227.5
6.500 Notes Due 2034 \| Senior Notes
Subsequent Event [Line Items]
Debt instrument, face amount	$ 500.0
Stated interest rate	6.50%
O 2025 Q2 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)				$ 0.35
O 2025 Q1 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)				0.35
O 2025 Q4 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)				0.35
O 2025 Q3 Regular Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)				0.35
O 2025 A Dividends
Subsequent Event [Line Items]
Dividends payable, amount per share (in USD per share)				$ 1.40

Significant Accounting Polices (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Significant Accounting Policies [Line Items]
Impairment of assets	$ 115.0	$ 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	100.00%
Percentage of acquired entity noncontrolling interest reported	20.00%
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	20.00%
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	50.00%

Supplemental Quarterly Information (Unaudited)

12 Months Ended

Dec. 31, 2025

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Information (Unaudited)


(Millions of dollars except per share amounts)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
Year ended December 31, 2025
Revenue from contracts with customers 1	$	672.7	$	683.0	$	721.0	$	613.1	$	2,689.8
Income (loss) from continuing operations before income taxes 1	122.8		34.9		(3.7)		28.9		182.9
Income (loss) from continuing operations 1	90.0		33.8		(7.8)		22.3		138.3
Net income (loss) including noncontrolling interest	89.4		35.1		(8.3)		22.6		138.8
Net income (loss) attributable to Murphy	73.0		22.3		(3.0)		11.9		104.2
Income (loss) from continuing operations per common share ²
Basic	0.51		0.15		(0.02)		0.08		0.73
Diluted	0.50		0.15		(0.02)		0.08		0.72
Net income (loss) per common share ²
Basic	0.51		0.16		(0.02)		0.08		0.73
Diluted	0.50		0.16		(0.02)		0.08		0.72
Cash dividend per common share	0.325		0.325		0.325		0.325		1.300
Year ended December 31, 2024
Revenue from contracts with customers 1	$	794.8	$	801.0	$	753.2	$	669.6	$	3,018.6
Income from continuing operations before income taxes 1	145.6		189.6		153.8		78.6		567.6
Income from continuing operations 1	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

Revenue from Contracts with Customers - Schedule of Current Long-Term Contracts Outstanding (Details) - Canada	Dec. 31, 2025 MMcf
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 , 2026
Disaggregation of Revenue [Line Items]
Approximate Volumes	49
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 2027
Disaggregation of Revenue [Line Items]
Approximate Volumes	30
Contracts to sell natural gas at USD index pricing \| End Date Quarter4 2028
Disaggregation of Revenue [Line Items]
Approximate Volumes	10
Contracts to sell natural gas at CAD fixed pricing \| End Date Quarter4 , 2026
Disaggregation of Revenue [Line Items]
Approximate Volumes	50
Contracts to sell natural gas at CAD fixed pricing \| End Date Quarter4 2027
Disaggregation of Revenue [Line Items]
Approximate Volumes	9

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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+ Details

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2025	Jan. 31, 2026	Jun. 30, 2025
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
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			$ 2,375,149,725
Entity Common Stock, Shares Outstanding		142,830,352
Documents Incorporated by Reference	Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 13, 2026 have been incorporated by reference in Part III herein.
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Entity Central Index Key	0000717423
Amendment Flag	false

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Cumulative preferred stock, shares issued (in shares)	0	0
Common Stock, par value (in USD per share)	$ 1.00	$ 1.00	$ 1.00
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)	52,315,476	49,255,504	42,351,986

Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2025

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Loss

Note N – Accumulated Other Comprehensive Loss


(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments			Total
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	(134,692)		27,737			(106,955)
Balance at December 31, 2024	(516,324)		(111,748)			(628,072)
2025 components of other comprehensive income (loss):
Before reclassifications to income	73,993		(3,633)			70,360
Reclassifications to income	—		3,485		¹	3,485
Net other comprehensive income (loss)	73,993		(148)			73,845
Balance at December 31, 2025	$	(442,331)	$	(111,896)		$	(554,227)

Assets and Liabilities Measured at Fair Value - Narratives (Details)	3 Months Ended			12 Months Ended
	Sep. 30, 2025 USD ($)	Dec. 31, 2024 USD ($) offsettingPosition	Mar. 31, 2024 USD ($)	Dec. 31, 2025 USD ($) offsettingPosition	Dec. 31, 2024 USD ($) offsettingPosition	Dec. 31, 2023 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Number of offsetting positions (in offsetting positions) \| offsettingPosition		0		0	0
Impairment of assets		$ 28,400,000	$ 34,500,000	$ 115,002,000	$ 62,909,000	$ 0
United States Offshore
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of assets				115,002,000	62,909,000
Impairment of assets excluding NCI	$ 92,000,000.0
Commodity swaps \| Accounts payable \| Not Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability		$ (1,707,000)		$ 0	$ (1,707,000)

- Definition

+ References + Details