What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2026-02-25 compared with 2025-02-27 · 192 added, 188 removed, 387 unchanged (50% of the section changed)

2 unchanged sentences

The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2020 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group.

XOP Index reports a comprehensive view of the oil and natural gas exploration and production segment of the S&P Total Market Index, which is more comparable for the Company than the S&P 500 Index.

XOP Index reports a comprehensive view of the oil and natural gas E&P segment of the S&P Total Market Index, which is more comparable for the Company than the S&P 500 Index.

Our peer group for 2025 is presented in the table below.

Civitas Resources Inc., EOG Resources Inc.

and Magnolia Oil & Gas Corporation were added to Murphy’s peer group in 2024.

Callon Petroleum Company, Hess Corporation and PDC Energy Inc.

were removed from Murphy’s peer group in 2024.

Chord Energy Corporation, Diamondback Energy, Inc., Expand Energy Corporation and Permian Resources Corporation were added to Murphy’s peer group in 2025.

Marathon Oil Corporation and Southwestern Energy Company were removed from Murphy’s peer group in 2025.

This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference.

The companies in the peer group include:

APA Corporation Kosmos Energy Ltd.

APA Corporation Expand Energy Corporation Permian Resources Corporation

Chord Energy Corporation

EOG Resources, Inc.

Range Resources Corporation

Civitas Resources, Inc.

Magnolia Oil & Gas Corporation

Kosmos Energy Ltd.

SM Energy Company

Coterra Energy Inc.

Marathon Oil Corporation 1

Southwestern Energy Company 1

Magnolia Oil & Gas Corporation Talos Energy Inc.

Devon Energy Corporation Matador Resources Company

Talos Energy Inc.

EOG Resources Inc.

Diamondback Energy, Inc.

2020 2021 2022 2023 2024 2025

Murphy Oil Corporation 100 221 372 380 278 302

Peer Group 100 64 132 201 191 180

S&P 500 Index 100 129 105 133 166 196

2025 Peer Group

100 211 318 315 309 298

2024 Peer Group

100 206 314 297 281 265

XOP Index 100 187 297 297 281 283

1 Marathon Oil Corporation and Southwestern Energy Company were acquired in 2024 and therefore have been excluded from the above table and graph of cumulative total return.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

3 unchanged sentences

Discussion and analysis of 2023 results and year-over-year comparisons between 2024 and 2023 are not included in this Form 10-K and can be found in “Item 7” of the 2024 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.

Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company with both onshore and offshore operations and properties.

The Company produces crude oil, natural gas and NGLs primarily in the U.S.

Murphy Oil Corporation is a worldwide oil and natural gas E&P company with both onshore and offshore operations and properties.

The Company produces oil and natural gas primarily in the U.S.

and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide.

4 unchanged sentences

• Produced 189 thousand BOEPD (182 thousand BOEPD excluding NCI);

• Issued $600.0 million of 6.000% senior notes due 2032, and used proceeds to redeem an aggregate $600.0 million of senior notes due 2027, 2028 and 2029;

• Entered into a new five-year, $1.35 billion senior unsecured credit facility, representing a 69% increase from previous facility size;

• Advances made under the capital allocation framework 1 :

◦ Repurchased $50.0 million of long-term debt;

◦ Repurchased 8.0 million shares of common stock under the share repurchase program for $300.0 million ($302.7 million including excise taxes and fees);

• Repurchased 3.6 million shares of common stock under the share repurchase program for $100.0 million ($100.8 million including excise taxes and fees) under the capital allocation plan 1 ;

• Achieved 101% (103% excluding NCI) total proved reserve replacement with year-end proved reserves of 730.0 million MMBOE (715.0 MMBOE excluding NCI);

• Drilled an oil discovery at Hai Su Vang-1X (Golden Sea Lion) in offshore Vietnam and encountered approximately 370 feet of net oil pay from two reservoirs;

• Drilled a discovery at the non-operated Ocotillo #1 exploration well in Mississippi Canyon 40 in the Gulf of America and found 100 feet of net pay across two zones.

1 Details of the capital allocation framework 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.

• Closed the strategic acquisition of the Pioneer floating production, storage and offloading vessel (FPSO) in the Gulf of America for a gross purchase price of $125.0 million;

• Drilled oil discoveries at the Lac Da Hong-1X (Pink Camel), Block 15-1/05 and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells in Vietnam.

Subsequent to year end:

• Issued $500.0 million of 6.50% senior notes due in 2034 and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;

• Upsized senior unsecured revolving credit facility from $1.35 billion to $2.00 billion and extended maturity from 2029 to 2031;

• Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced a dry hole at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire;

• Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.

1 Details of the capital allocation plan 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.

The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Murphy’s continuing operations generate revenue by producing crude oil, natural gas and NGLs in the U.S.

Murphy’s continuing operations generate revenue by producing oil and natural gas in the U.S.

and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and NGLs.

In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

The Company’s revenue is affected by the prices of oil and natural gas.

In order to make a profit and generate cash in its E&P business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

For the year ended December 31, 2025, the Company’s net income from continuing operations was $138.3 million, a decrease of $351.0 million compared to 2024.

Lower net income from continuing operations was largely driven by lower revenues and other income ($431.7 million), higher lease operating expenses ($152.7 million), and higher impairment expense ($62.9 million), partially offset by lower income tax expense ($117.6 million), lower exploration expenses ($101.2 million), higher other income ($79.5 million), lower other operating expense ($35.5 million) and lower transportation, gathering and processing costs ($22.2 million).

Lower revenues from production were primarily driven by mechanical and weather downtime in the Gulf of America, timing and performance of new wells at Eagle Ford Shale and lower average oil and natural gas prices, partially offset by wells brought back online at the non-operated Terra Nova field in the fourth quarter of 2023.

Higher lease operating expenses were primarily due to workovers in the Gulf of America and higher production activity in Canada at the Terra Nova field, partially offset by lower production handling fees in the Gulf of America.

Higher impairment expense is due to impairment of the Calliope and Nearly Headless Nick fields in the Gulf of America.

The decrease in income tax expense is primarily driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend.

Exploration expenses in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of America, including Sebastian #1 (Mississippi Canyon 387), non-operated Orange #1 (Mississippi Canyon 216), and for previously suspended exploration costs related to an expired lease at Hoffe Park #1 (Mississippi Canyon 166).

Higher other income related to unrealized foreign exchange gains and interest income on several outstanding joint interest receivables.

Lower other operating expense in 2024 is primarily driven by lower non-operated Terra Nova field start-up costs, contingency adjustments and asset retirement obligations (ARO) revisions.

Lower interest expense was due to lower debt levels.

Lower transportation, gathering and processing expenses related to lower production in the U.S.

For the year ended December 31, 2024, total hydrocarbon production was 184,293 BOEPD, a decrease of 4% compared to 2023.

The decrease was principally due to lower production in the U.S., primarily in the Gulf of America due to downtime for wells awaiting workovers and in the Eagle Ford Shale due to timing and performance of new wells and partially offset by the restart of production at the non-operated Terra Nova field in Canada in the first quarter of 2024.

Lower net income from continuing operations was largely driven by lower revenues and other income ($309.7 million), higher depreciation, depletion and amortization expense (DD&A) ($112.0 million), higher other losses ($93.2 million), higher impairment expense ($52.1 million) and higher selling and general expenses ($27.2 million).

These items were partially offset by lower lease operating expenses ($171.7 million), lower income tax expense ($33.7 million), and lower exploration expenses ($21.9 million).

Lower revenues from production were primarily driven by lower average oil prices and lower volumes in the Gulf of America due to downtime and the natural decline of new wells, and was partially offset by increased production in the Eagle Ford Shale due to new wells and improved performance, as well as higher realized natural gas prices in Canada, at the Tupper Montney.

Higher DD&A was primarily due to increased production and higher rates in the Eagle Ford Shale, and higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.

Higher other losses were mainly due to unrealized losses on foreign exchange related to our Canada business and were partially offset by lower interest expenses due to no debt repayment fees in the current year.

Impairment expense of $115.0 million in 2025 was related to the impairment of the Dalmatian property due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

Higher selling and general expenses were due to higher salary and compensation costs in 2025.

Lower lease operating expenses were due to lower workovers in the current year, combined with lower operating costs related to the purchase of the Pioneer FPSO.

Lower income tax expense was primarily attributable to lower taxable income and was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend.

Lower exploration expenses were due to lower dry hole costs in the current period, which related to the Civette-1X (Block CI-502) exploration well in C ôte d’Ivoire, and was partially offset by higher exploration, geological, geophysical and other costs related to the Company’s U.S.

Offshore and C ôte d’Ivoire exploration programs.

For the year ended December 31, 2025, total hydrocarbon production was 188,682 BOEPD, an increase of 2% compared to 2024.

The increase was principally due to higher production in the Eagle Ford Shale and Canada Onshore and was partially offset by lower production in the Gulf of America.

Increased production in the Eagle Ford Shale was driven primarily by the performance of new wells online in the current year at Karnes and Catarina.

Higher production in Canada Onshore related to better well performance at the Tupper Montney.

Lower production in the Gulf of America related to planned and unplanned downtime and was partially offset by new wells online.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

12 unchanged sentences

138.3 489.3 725.2

Loss from discontinued operations 1

Income (loss) from discontinued operations 1

0.5 (2.8) (1.5)

5 unchanged sentences

$ 104.2 $ 407.2 $ 661.6

1 The Company has presented its former U.K., Malaysia and U.S.

1 The Company has presented its former U.K.

refining and marketing operations as discontinued operations in its consolidated financial statements.

E&P Continuing Operations:

The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.

The following section of E&P continuing operations excludes the Corporate segment, unless otherwise noted.

Please also refer to “ Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities ” in the Supplemental Oil and Natural Gas Information section for additional supporting tables.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following is a summarized statement of operations for E&P continuing operations.

4 unchanged sentences

Sales of purchased natural gas

3.7 72.2 181.7

Gain on sale of assets and other operating income

Total revenues and other income

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Results of operations before taxes 386.9 704.7 1,119.0

Income tax provisions

Income tax expense

90.2 106.3 237.8

1 unchanged sentence

$ 296.7 $ 598.4 $ 881.2

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains the weighted average sales prices for the three years ended December 31, 2025:

(Weighted average sales prices)

2025 2024 2023

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1.79 1.59 2.06

1 Prices include the effect of noncontrolling interest in MP GOM.

1 Prices include the effect of the noncontrolling interest in MP GOM.

dollar equivalent.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2025:

1 unchanged sentence

WTI ($/BBL) $ 64.81 $ 75.72 $ 77.62

NYMEX ($/MMBTU) 2.24 2.53 6.38

Henry Hub ($/MMBTU)

3.54 2.24 2.53

AECO (C$/MCF) 1.68 1.46 2.64

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Production Volumes

31 unchanged sentences

507,950 481,042 466,008

Total net hydrocarbons - including NCI 2,3

Total net hydrocarbons - including noncontrolling interest 2

188,682 184,293 192,640

5 unchanged sentences

(6,388) (6,881) (6,778)

Total net hydrocarbons - excluding NCI 2,3

Total net hydrocarbons - excluding noncontrolling interest 2

182,294 177,412 185,862

2 unchanged sentences

730.0 729.0 739.5

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

1 Includes net volumes attributable to the noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

4 December 31, 2024, 2023 and 2022, include 15.9 MMBOE, 15.5 MMBOE and 18.2 MMBOE, respectively, relating to

noncontrolling interest.

3 Proved reserves at December 31, 2025, 2024 and 2023, include 15.0 MMBOE, 15.9 MMBOE and 15.5 MMBOE, respectively, attributable to NCI.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

32 unchanged sentences

507,950 481,042 466,008

Total net hydrocarbons - including NCI 2,3

Total net hydrocarbons - including noncontrolling interest 2

188,838 184,063 192,178

5 unchanged sentences

(6,349) (6,960) (6,768)

Total net hydrocarbons - excluding NCI 2,3

Total net hydrocarbons - excluding noncontrolling interest 2

182,489 177,103 185,410

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

1 Includes net volumes attributable to the noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

11 unchanged sentences

275.8 232.3 278.2

6.6 11.0 22.8

Total revenues from production

1 unchanged sentence

Revenues from production in 2025 decreased by $325.1 million compared to 2024.

Revenue was lower in the Gulf of America, mostly driven by downtime for workovers, hurricane-related downtime and timing of new wells.

Eagle Ford Shale revenues decreased due to timing and performance of wells brought online.

These decreases were partially offset by wells brought back online in the fourth quarter of 2023 at non-operated Terra Nova.

Lower pricing across all products also contributed to the decrease during the period.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments.

“Sales of purchased natural gas” is included in “Total revenues and other income” and “Costs of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 33 .

Sales of purchased natural gas during 2024 were $3.7 million.

Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline, and downtime for maintenance at Khaleesi.

These decreases were partially offset by wells online at Mormont and Neidermeyer in the Gulf of America, improved performance, new wells, and the acquisition of additional working interests in the Eagle Ford Shale, and new wells and improved performance in the Tupper Montney.

Higher realized gas pricing in the period was also an offset to the decrease in revenue.

Gain on Sale of Assets and Other Operating Income

Other income was $17.6 million in 2025, an increase of $11.6 million compared to 2024.

Higher other income was primarily the result of a gain recognized on contingent consideration related to the 2022 sale of working interests in Block CA-2 in Brunei.

Lease Operating and Transportation, Gathering and Processing Expenses

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Total transportation, gathering and processing $ 199.7 $ 210.8 $ 233.0 $ 2.90 $ 3.13 $ 3.32

Lease operating expenses and transportation, gathering and processing expenses in 2024 increased by $152.6 million and decreased by $22.2 million, respectively, compared to 2023.

Higher lease operating expenses were primarily due to workover costs in the Gulf of America, particularly at the Samurai and Neidermeyer fields, and the restart of the non-operated Terra Nova field in Canada Offshore in the first quarter of 2024.

Lease operating expenses and transportation, gathering and processing expenses in 2025 decreased by $171.8 million and $11.1 million, respectively, compared to 2024.

Lower lease operating expenses were primarily due to lower workover costs in the Gulf of America, lower operating costs as a result of the acquisition of the Pioneer

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

partially offset by lower production handling fees and lower overall volumes.

Lower transportation, gathering and processing expenses were primarily due to lower volumes.

FPSO and lower production handling fees.

In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, and were partially offset by higher volume related costs.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization expense by geographic area was as follows:

The Company’s DD&A expense by geographic area was as follows.

(Millions of dollars) (Dollars per equivalent barrel)

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$ 969.4 $ 856.9 $ 850.5 $ 14.06 $ 12.72 $ 12.12

Depreciation, depletion and amortization expense (DD&A) in 2024 increased by $6.4 million compared to 2023.

Higher DD&A was primarily the result of higher volumes at the non-operated Terra Nova field in Canada Offshore and higher rates at Eagle Ford Shale and in the Gulf of America, and was partially offset by lower volumes in the Gulf of America and lower rates and volumes at Kaybob Duvernay.

DD&A in 2025 increased by $112.5 million compared to 2024.

The increase was primarily due to higher sales volumes and higher rates in the Eagle Ford Shale, higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.

Impairment of Assets

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

In 2024, the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million.

In the first quarter of 2024, the Company recognized an impairment expense of $34.5 million for the Calliope field.

In the fourth quarter of 2024, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field.

In the first quarter, the Company recognized an impairment expense of $34.5 million for the Calliope field.

In the fourth quarter, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field.

Both fields were impaired as a result of operational issues that led to reserve reductions.

There were no impairments recorded in 2023.

Exploration Expenses

9 unchanged sentences

Exploration expenses in 2025 decreased by $21.8 million compared to 2024.

In 2025, dry holes were related to the operated Civette-1X (Block CI-502) exploration well in C ôte d’Ivoire .

In 2024, dry holes and previously suspended exploration costs primarily related to the Sebastian #1 (Mississippi Canyon 387) exploration well, the non-operated Orange #1 (Mississippi Canyon 216) exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America.

In 2023, dry holes and previously suspended exploration costs related to previously suspended exploration costs for the Cholula-1EXP well in offshore Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well and the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America, both of which encountered non-commercial hydrocarbons.

The decrease due to lower dry hole costs was partially offset by increases to geological, geophysical and other exploration costs, related to the Company’s Gulf of America and Côte d'Ivoire exploration programs.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Selling and General Expenses

Selling and general expenses were $46.2 million in 2025, an increase of $22.4 million compared to 2024.

Selling and general expenses were higher due to higher salary and long-term incentive compensation costs primarily related to a higher average share price throughout 2025.

Other Expenses

Other expenses were $0.3 million in 2024, a decrease of $56.6 million compared to 2023.

Other expenses were lower primarily due to the absence of other operating expenses in Canada related to the non-operated Terra Nova life extension project, lower asset retirement adjustments, no contingent consideration adjustments in the current period and higher interest income received in 2024.

Total other losses were $16.5 million in 2025, an increase of $16.2 million compared to 2024.

The increase was primarily due to no repeat of interest income on outstanding joint interest receivables that was received in 2024.

Income taxes were $90.2 million in 2025, a decrease of $16.1 million compared to 2024.

Lower income taxes were primarily the result of lower pretax income, and an income tax deduction for prior years’ Australia exploration spend (see Note H ).

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of oil sold) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments result from increases in market oil and natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $109.1 million in 2024, a favorable variance of $46.9 million compared to 2023.

The favorable variance was primarily due to foreign exchange gain of $45.4 million in 2024 compared to foreign exchange loss of $10.7 million in 2023, primarily as a result of unrealized exchange rate changes relating to our Canadian subsidiary.

Interest charges are lower in 2024 primarily due to lower overall debt levels.

The lower income tax benefit was the result of a lower current period loss before income tax.

Lower income taxes were primarily the result of lower pretax income.

This was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend.

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of natural gas sold) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments result from increases in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $158.4 million in 2025, an unfavorable variance of $49.3 million compared to 2024.

The unfavorable variance was primarily due to a foreign exchange loss of $29.4 million in 2025 compared to a foreign exchange gain of $45.4 million in 2024, as a result of unrealized exchange rate changes relating to our Canadian subsidiary.

This increase was partially offset by lower interest charges in 2025 due to no debt repayment fees in the current year, and a higher income tax benefit attributable to our Canadian segment as a result of larger current-period losses before income taxes, primarily as a result of foreign exchange.

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured RCF, as described below.

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF, as described below.

The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

9 unchanged sentences

(264.1) (716.5) (923.7)

Net cash required by discontinued operations

Effect of exchange rate changes on cash and cash equivalents (1.2) 2.2 (1.2)

1 unchanged sentence

$ (46.4) $ 106.5 $ (174.8)

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities in 2025 was $481.2 million lower compared to 2024.

The decrease was primarily attributable to lower revenue from production ($361.7 million) and higher lease

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

operating expenses costs ($152.6 million), partially offset by a decrease due to timing of non-cash working capital ($174.2 million) settlements, no contingent consideration payments related to prior Gulf of America acquisitions in 2024 (2023:

$139.6 million), lower exploration expenses ($101.2 million), and changes in other operating activities, net ($56.4 million) primarily due to decreased expenditures for asset retirements.

Payments of contingent consideration in 2023 are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows;

amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition.

Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.

During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows.

As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of America acquisitions.

See Note O for further details.

The decrease was primarily attributable to lower revenue from production ($325.1 million), timing of non-cash working capital ($148.9 million) settlements, changes in other operating activities, net ($68.4 million), primarily due to decreased expenditures for asset retirements, and higher other expenses ($93.2 million), primarily due to Canadian foreign exchange losses, partially offset by lower lease operating expenses ($171.7 million) and lower exploration expenses $21.9 million.

The total reductions of operating cash flows for interest paid (which excludes “Early redemption of debt cost” reported in “Financing Activities”) during the two years ended December 31, 2025, and 2024 were $88.1 million and $78.8 million, respectively.

Cash interest paid in 2025 was primarily due to interest payments on outstanding debt.

Some of these payments related to accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) in the aggregate redemption amount of $650.1 million.

In 2023, cash interest paid was higher than 2024, primarily due to higher debt levels in 2023 and accelerated interest payments due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 2027 Notes, the 2028 Notes, and the 2029 Notes for an aggregate redemption amount of $498.2 million.

In 2025, cash interest paid was higher than 2024, primarily due to amounts drawn on the RCF.

In 2024, cash interest paid was primarily due to interest payments on outstanding debt and accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) for an aggregate redemption amount of $650.1 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2024 was $90.5 million lower compared to 2023.

The decrease was primarily due to lower property additions and dry hole costs ($157.9 million) and lower acquisition capital ($35.6 million), partially offset by the absence of proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million).

Net cash required by investing activities in 2025 was $120.8 million higher compared to 2024.

The increase was primarily due to higher property additions ($120.5 million) and higher acquisition capital ($21.0 million), partially offset by proceeds from realization of contingent consideration receivable from the 2022 sale of Brunei assets.

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

5 unchanged sentences

Acquisition of oil and natural gas properties per the cash flow statements

29.0 8.1 35.6

Capital expenditure accrual changes and other 102.8 11.8 (9.5)

Total capital expenditures $ 1,218.0 $ 964.8 $ 1,138.1

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Total accrual basis capital expenditures are shown below.

Total capital expenditures categorized by E&P and corporate activities are presented below.

Year Ended December 31,

4 unchanged sentences

Total capital expenditures 1,218.0 964.8 1,138.1

Total capital expenditures excluding proved property acquisitions 964.8 1,111.0 1,054.7

Total capital expenditures excluding proved property acquisitions and NCI $ 952.8 $ 1,040.8 $ 1,028.8

Lower capital expenditures in 2024 compared to 2023 were primarily attributable to lower development expenditures at Eagle Ford Shale, Tupper Montney, and non-operated Terra Nova and lower exploration expenses in the Gulf of America, partially offset by higher exploration and development costs in offshore Vietnam.

Capital expenditures in 2024 primarily relate to development drilling and field development activities in the Gulf of America, primarily related to the Mormont, Khaleesi, Lucius, St.

Malo and Samurai fields ($306.9 million), at Eagle Ford Shale ($291.8 million), at Tupper Montney and Kaybob Duvernay ($116.3 million), at other international locations ($45.1 million), and at non-operated Hibernia ($18.2 million).

In addition, total exploration costs were $153.9 million.

Exploration costs in 2024 were primarily comprised of activities in the Gulf of America related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and non-operated Oso #1 (Atwater Valley 138) exploration wells.

Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024.

Non-operated Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024.

Additional exploratory costs relate to oil discoveries, including 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, as well as other ongoing projects.

acquisition of oil and natural gas properties

29.0 8.1 35.6

Total capital expenditures excluding acquisition of oil and natural gas properties

1,189.0 956.7 1,102.5

Total capital expenditures excluding acquisition of oil and natural gas properties and noncontrolling interest

$ 1,157.0 $ 944.7 $ 1,032.3

Higher capital expenditures in 2025 compared to 2024 were primarily attributable to the Pioneer FPSO purchase in the Gulf of America, exploratory and development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign, and exploratory drilling in Côte d’Ivoire.

Capital expenditures of $1,218.0 million in 2025 were primarily related to development drilling ($551.4 million), field development ($400.2 million) and exploration ($221.7 million) activities.

Development activities were mainly in the Gulf of America ($330.8 million), primarily related to the Cascade and Chinook, Mormont,

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Zephyrus, and Other Offshore fields, the Eagle Ford Shale ($365.4 million), the Tupper Montney and the Kaybob Duvernay ($133.9 million), and Vietnam ($98.5 million).

Exploration costs in 2025 were $221.7 million, primarily attributable to activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05, and Hai Su Vang-1X and Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d’Ivoire related to the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.

Cash Required by Financing Activities

Net cash required by financing activities in 2025 decreased by $452.4 million compared to 2024.

In 2024, cash used in financing activities was principally for the repurchase of common shares ($301.4 million, excluding excise tax).

In addition, the Company completed a refinancing transaction whereby new senior notes due 2032 were issued in the aggregate amount of $600.0 million and the proceeds were used for the aggregate repayment and repurchase of $600.0 million of its 2027 Notes, 2028 Notes and 2029 Notes.

The Company also repurchased $50.0 million of its 2027 Notes, paid cash dividends to shareholders of $1.20 per share ($180.0 million), and distributed funds to the noncontrolling interest in MP GOM ($118.6 million).

At December 31, 2024, the Company had approximately $1.8 billion of liquidity consisting of $423.6 million in cash and cash equivalents and $1,349.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029.

As of December 31, 2024, the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF.

Borrowings under the RCF are subject to certain interest rates.

In 2025, cash used in financing activities was principally for year-to-date cash dividends to shareholders of $1.30 per share ($186.2 million), the repurchase of common shares ($102.6 million), excluding excise tax, distributions to the noncontrolling interest in MP GOM ($63.8 million), and partially offset by net borrowings on the RCF ($100.0 million).

At December 31, 2025, the Company had approximately $1.6 billion of liquidity consisting of $377.2 million in cash and cash equivalents and $1,249.6 million available on its previous RCF with a major banking consortium.

The Company’s previous $1.35 billion RCF was set to expire in October 2029, and as of December 31, 2025, the Company had $100.0 million outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

Borrowings under the RCF were subject to certain interest rates.

Please refer to Note F for further details.

At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68%.

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.

Subsequent to year end, in January, 2026, the Company entered into an Amended RCF, a credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility, with a maturity date in January 2031, which increased and extended the previous RCF.

Cash and invested cash are maintained in several operating locations outside the U.S.

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dollar equivalents of approximately $152.5 million (2024:

$149 million), the majority of which was held in Canada ($58.5 million), Vietnam ($8.7 million) and Brunei ($8.5 million).

In addition, approximately $7.8 million and $6.4 million of cash was held in the U.K.

and Mexico, respectively.

In certain cases, the Company could incur cash taxes or other costs should these cash balances be

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

repatriated to the U.S.

$95.2 million), the majority of which was held in Canada ($76.5 million), Brunei ($23.7 million), Côte d’Ivoire ($21.6 million), and Vietnam ($8.5 million).

In addition, approximately $7.8 million and $7.0 million of cash was held in Mexico and the U.K., respectively.

In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S.

in future periods.

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Working Capital

(Millions of dollars) December 31, 2024 December 31, 2023

(Millions of dollars) 2025 2024

Working capital

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As of December 31, 2025, net working capital had an unfavorable decrease of $88.5 million compared to December 31, 2024.

The decrease was primarily attributable to lower accounts receivable ($71.5 million), higher operating lease liabilities ($45.4 million), higher current ARO liabilities ($37.4 million), and higher accounts payable ($25.3 million), partially offset by a higher cash balance ($106.5 million).

Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas, and lower pricing received for all crude oil, natural gas and NGLs.

Higher operating lease liabilities are primarily due to an extension of an existing drilling ship lease in the Gulf of America.

Higher current ARO liabilities are primarily due to certain Gulf of America obligations to be completed in 2025.

Higher accounts payable are due to the timing of payments for certain drilling activities and ongoing workover projects.

The decrease was primarily attributable to higher accounts payable ($100.0 million), higher operating lease liabilities ($25.6 million), and a lower cash balance ($46.4 million), partially offset by higher accounts receivable ($74.2 million).

Higher accounts payable were primarily due to the timing of payments for certain drilling activities and ongoing workover projects.

Higher operating lease liabilities were primarily due to the addition of a new drilling rig and support vessels in Vietnam, partially offset by the purchase of the Pioneer FPSO and normal amortization of leases.

Higher accounts receivable were due primarily to timing of partner billing and related cash calls, partially offset by lower pricing.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Capital Employed

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Total capital employed $ 6,501.0 100.0 % $ 6,468.8 100.0 %

As of December 31, 2024, long-term debt decreased by $53.9 million compared to December 31, 2023, as a result of the repurchase of the 2027 Notes and 2028 Notes.

The Company also completed a refinancing transaction whereby it issued $600.0 million of 2032 Notes, and used all of the proceeds to complete the repurchase and redemption, in whole or in part, of the 2027 Notes, 2028 Notes, and 2029 Notes.

As of December 31, 2025, long-term debt increased by $108.1 million compared to December 31, 2024, primarily as a result of amounts drawn on the RCF.

As of December 31, 2025, the fixed-rate notes had a weighted average maturity of 8.3 years and a weighted average coupon of 6.1%.

Refer to Note F for additional details.

Murphy’s shareholders’ equity decreased by $168.5 million in 2024 primarily due to cash dividends paid ($180.0 million), shares repurchased ($302.7 million, including excise tax), and foreign currency translation losses ($134.7 million), partially offset by net income earned ($407.2 million).

Murphy’s shareholders’ equity decreased by $75.9 million in 2025 primarily due to dividends ($186.2 million) and shares repurchased ($100.8 million), including excise tax, partially offset by foreign currency translation ($74.0 million), net income ($104.2 million), and awarded restricted stock ($22.4 million).

A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity " on page 72 of this Form 10-K report.

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Other significant changes in Murphy’s balance sheet at the end of 2025, compared to 2024 are discussed below.

Property, plant and equipment, net of depreciation decreased $170.5 million principally due to DD&A expense and foreign exchange rates applicable for the Canadian assets, substantially offset by capital expenditures in the year.

Property, plant and equipment, net of depreciation, increased $81.7 million principally due to capital expenditures in the year, partially offset by DD&A expense ($977.8 million) and foreign exchange rates applicable for the Canadian assets.

Capital expenditures are discussed above in the “ Cash Required by Investing Activities ” section.

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$417.0 million).

This amount includes $220.0 million for Other Offshore, primarily related to approved expenditures for capital projects relating to interests in Vietnam for the Lac Da Vang (Golden Camel) field development project, $112.2 million at Eagle Ford Shale, primarily at the Karnes field, $53.6 million relating to

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Gulf of America interests, primarily at the Mormont and non-operated St.

Malo fields, and $31.2 million relating to interests in Canada Onshore, primarily at Kaybob Duvernay.

Operating lease assets increased $32.4 million principally due to lease extensions in the Gulf of America, partially offset by the depreciation of these assets.

Long-term ARO liabilities increased $56.8 million primarily due to accretion, additions and revisions related to Gulf of America and Eagle Ford Shale operations.

Non-current operating lease liabilities decreased $14.5 million primarily due to 2024 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.

Deferred income tax liabilities increased $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax effect s.

This amount primarily related to approved expenditures of $127.5 million in Vietnam for the Lac Da Vang (Golden Camel) field development project, $45.0 million for exploration activities in Côte d’Ivoire, $82.6 million in the Eagle Ford Shale, $245.3 million relating to Gulf of America interests, primarily related to Cascade and Chinook operated field and exploration activities, as well as $49.8 million relating to interests in Canada Onshore, primarily at the Kaybob Duvernay.

Operating lease assets increased $27.9 million principally due to lease additions in Vietnam, partially offset by the depreciation of these assets.

Deferred income tax liabilities increased $42.5 million due to utilization of our net operating loss, partially offset by other capital-related tax effects.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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The Company uses other operational performance and income metrics to review operational performance.

Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted net income excludes certain items that management believes affects the comparability of results between periods.

Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods.

Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

Adjusted net income, EBITDA, and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for net income or cash provided by operating activities as determined in accordance with GAAP.

The following table reconciles net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

Year Ended December 31,

(Millions of dollars)

2024 2023 2022

(Millions of dollars, except per share amounts) 2025 2024 2023

Net income attributable to Murphy (GAAP) 1

$ 104.2 $ 407.2 $ 661.6

Discontinued operations loss 2.8 1.5 2.1

Net income from continuing operations attributable to Murphy

410.0 663.1 967.1

Discontinued operations (income) loss (0.5) 2.8 1.5

Net income from continuing operations 103.7 410.0 663.1

Impairment of assets 1

Write-off of previously suspended exploration well

26.1 17.1 22.7

Foreign exchange (gain) loss 29.4 (45.4) 10.9

(45.4) 10.9 (23.0)

Refinancing and early redemption of debt costs (non-cash)

Mark-to-market loss (gain) on derivative instruments

1.7 — (214.7)

Unrealized (gain) loss on derivative instruments (1.7) 1.7 —

Write-off of previously suspended exploration well — 26.1 17.1

Unrealized loss on contingent consideration — — 7.1

Asset retirement obligation losses — — 16.9

Mark-to-market loss on contingent consideration

(Gain) on sale of assets — — (14.5)

Refinancing and early redemption of debt costs (non-cash) — 3.7 —

Total adjustments, before taxes 119.7 49.0 52.0

49.0 52.0 (110.1)

Income tax (benefit) expense related to adjustments (26.4) (8.3) (6.4)

Tax (benefit) on investments in foreign areas

Tax benefits on investments in foreign areas — (34.0) —

Total adjustments, after taxes 93.3 6.7 45.6

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 197.0 $ 416.7 $ 708.7

Net income from continuing operations per average diluted share (GAAP)

$ 2.72 $ 4.23 $ 6.14

Adjusted net income from continuing operations attributable to Murphy per average diluted share (Non-GAAP)

Net income from continuing operations per average diluted share

$ 0.72 $ 2.72 $ 4.23

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 1.37 $ 2.76 $ 4.52

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.

The following table reconciles net income attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.

Year Ended December 31,

(Millions of dollars) 2025 2024 2023

2024 2023 2022

Net (loss) income attributable to Murphy (GAAP) 1

Net income attributable to Murphy (GAAP) 1

$ 104.2 $ 407.2 $ 661.6

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Depreciation, depletion and amortization expense ¹ 946.8 833.1 836.7

833.1 836.7 748.2

EBITDA attributable to Murphy (Non-GAAP) $ 1,191.7 $ 1,424.5 $ 1,806.6

Impairment of assets 1

Accretion of asset retirement obligations 1

Exploration expenses 1

111.6 133.5 204.6

EBITDAX attributable to Murphy (Non-GAAP) $ 1,303.3 $ 1,558.0 $ 2,011.2

EBITDA attributable to Murphy (Non-GAAP) $ 1,191.7 $ 1,424.5 $ 1,806.6

Impairment of asset 1

Foreign exchange (gain) loss 29.4 (45.4) 10.8

(45.4) 10.8 (23.0)

Accretion of asset retirement obligations ¹ 51.5 46.9 41.0

Unrealized (gain) loss on derivative instruments (1.7) 1.7 —

Write-off of previously suspended exploration well — 26.1 17.1

Discontinued operations loss

Mark-to-market loss (gain) on derivative instruments

1.7 — (214.7)

Mark-to-market loss on contingent consideration

Asset retirement obligation losses — — 16.9

Gain on sale of assets 1

Unrealized loss on contingent consideration — — 7.1

Discontinued operations (income) loss (0.5) 2.8 1.5

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,362.4 $ 1,519.5 $ 1,901.0

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

Other exploration expenses 2

111.6 107.4 187.5

Adjusted EBITDAX attributable to Murphy (Non-GAAP) $ 1,474.0 $ 1,626.9 $ 2,088.5

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

2 Other exploration expenses consist of exploration expenses as reported in the Consolidated Statements of Operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Management uses FCF and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities.

Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time.

FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.

The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.

Year Ended December 31,

(Millions of dollars) 2025 2024 2023

Net cash provided by continuing operations activities (GAAP) $ 1,247.8 $ 1,729.0 $ 1,748.8

(decrease) increase in non-cash working capital 74.1 (74.9) 99.4

Operating cash flow excluding working capital adjustments 1,321.9 1,654.1 1,848.2

property additions and dry hole costs 1

(1,020.6) (900.1) (1,066.0)

Free cash flow (Non-GAAP) $ 301.3 $ 754.0 $ 782.2

cash dividends paid (186.2) (180.0) (171.0)

distributions to noncontrolling interest (63.8) (118.6) (29.4)

debt costs (0.4) (40.6) —

contingent consideration payment — — (60.2)

withholding tax on stock-based incentive awards (9.8) (25.3) (14.3)

acquisition of oil and natural gas properties (29.0) (8.0) (35.6)

Adjusted free cash flow (Non-GAAP) $ 12.1 $ 381.5 $ 471.7

1 Property additions for the year ended December 31, 2025 include a payment of $125.0 million for the Pioneer FPSO in the U.S.

Offshore, including amounts attributable to the noncontrolling interest in MP GOM.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Environmental, Health and Safety Matters

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and the health and safety of our employees, contractors and communities where our operations are located.

These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.

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.

Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.

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Other Matters

Impact of inflation – In 2024, many countries worldwide continued to experience moderate inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

Impact of inflation – In 2025, inflation in the U.S.

and in other countries where the Company operates began to moderate relative to the sustained higher inflation seen since 2021.

However, U.S.

and global trade policy is continually developing, and it is unclear whether this trend will continue or reverse as we enter 2026 and beyond.

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation.

Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC and certain non-OPEC members’ production levels and/or attitudes of traders concerning supply and demand in the future.

Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ members’ production levels and/or attitudes of traders concerning supply and demand in the future.

Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.

To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply chain and input costs.

Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services.

However, from time to time,

Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity