MURPHY OIL CORP

These notes are an integral part of the consolidated financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 73-110 of the Form 10-K report.

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 thethree-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 oftwo orthree 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. See Note L.

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

Note B - New Accounting Principles and Recent Accounting Pronouncements (Continued)

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.

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 intotwo 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 ontwo key geographical segments and between onshore and offshore sources of revenue within these geographies.

Note C - Revenue from Contracts with Customers (Continued)

The Company’s revenues and other income for each of the three years presented were as follows.

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.

Note C - Revenue from Contracts with Customers (Continued)

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.

The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes.

Note D – Property, Plant and Equipment

The Company’s property, plant and equipment assets for the respective periods are presented as follows:

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.

Note D – Property, Plant and Equipment (Continued)

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 oftwo 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.

Note D – Property, Plant and Equipment (Continued)

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 wereno impairments recognized in 2023.

Note E – Inventories

Inventories consisted of the following for the respective periods presented.

Note F – Financing Arrangements and Debt

Long-term debt for the respective periods presented consisted of the following.

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 3.25 x and a minimum consolidated interest coverage ratio of 2.50 x. 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 publishedtwo 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.

Note F - Financing Arrangements and Debt (Continued)

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.

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.

Note G - Asset Retirement Obligations (Continued)

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

As of December 31, 2025, there were $46.5 million in compensation costs, to be expensed over approximately the nexttwo 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.

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.

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.

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.

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.

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.

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.

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.

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

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

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.

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.

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.

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.

At December 31, 2024, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.

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 offour 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:

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.

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:

Note K – Financial Instruments and Risk Management (Continued)

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:

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company hadno 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.

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.

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.

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.

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

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

Note N – Accumulated Other Comprehensive Loss

The components of ”Accumulated other comprehensive loss” on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table.

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.

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.

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 wereno 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

Note O – Assets and Liabilities Measured at Fair Value (Continued)

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 wereno offsetting positions recorded at December 31, 2025 and 2024.

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.

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.

Note O – Assets and Liabilities Measured at Fair Value (Continued)

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.

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.

Note Q – Environmental and Other Contingencies (Continued)

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to 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

Note Q - Environmental and Other Contingencies (Continued)

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.

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.

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.

Note S – Business Segments

Murphy’sreportable 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.

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.

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.

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.

Note T – Leases (Continued)

Related Expenses

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

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.

Maturity of Lease Liabilities

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

Note T – Leases (Continued)

Lease Term and Discount Rate

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 andtwo 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.

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 toredeem 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.