MURPHY OIL CORP

The Company’s production revenues by country and product were as follows.

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

The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows.

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

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 DD&A expense by geographic area was as follows.

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, 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.

Exploration Expenses

The Company’s exploration expenses were as follows.

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 Côte 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. 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.

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

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

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. 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: 2025 vs 2024

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 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. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months.

Cash Flows

The following table presents the Company’s cash flows for the periods presented.

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 ($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. 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 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.

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

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,

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 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).

Liquidity

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, 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. As of December 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $152.5 million (2024: $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. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S. See Note Hfor further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the U.S.

Working Capital

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 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.

Capital Employed

A summary of capital employed as of December 31, 2025 and 2024 follows.

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 $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.

Other Balance Sheet Activity - Long-Term Assets and Liabilities

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, 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.

Murphy had commitments for capital expenditures of approximately $551.2 million at December 31, 2025 (2024: $417.0 million). 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.

Other Key Performance Metrics

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), 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, 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.

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

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

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 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.

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.

Environmental, Health and Safety Matters

Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, auditing and assessments, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and approved by a Health, Safety, Environment and Corporate Responsibility Committee consisting of certain members of the Board.

The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations. Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.

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; the placement, operation and decommissioning of production equipment; 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 of facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.

Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the “Business” section beginning page 9.

Climate Change and Emissions

The world’s population and standard of living are growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of GHG, which could raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the TCFD framework. While oversight of the TCFD framework has undergone changes, including relating to the role of the International Financial Reporting Standards Foundation in overseeing the framework, the TCFD framework continues to inform climate-related reporting practices. Murphy’s disclosures related to its alignment with the TCFD framework are included in the Company’s 2025 Sustainability Report issued on August 6, 2025, which is not incorporated by reference hereto.

Other Matters

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+ 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 partially protected from potential increases in the price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher costs. Murphy continues to strive toward safely executing our work in an ever-increasingly efficient manner to mitigate potential inflationary pressures in its business.

Natural gas prices are also affected by supply and demand factors, which are often influenced by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas. Natural gas prices can also be impacted by the demand for lower-carbon energy sources.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.

Oil and natural gas proved reserves – Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain). Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use an unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas prices and reserve assumptions when making its own internal economic property evaluations. Changes in oil and natural gas prices can lead to a decision to start up or shut in production, which can lead to revisions to reserves quantities.

Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligation (ARO) liabilities. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods.

The Company’s proved reserves of oil and natural gas are presented on pages 111 to 120 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), and commercially available technologies, to establish “reasonable certainty” of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies.

Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. It was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2025 beginning on pages 4 and 111 of this Form 10-K report.

Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheets to ensure that they are fairly presented. The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from undiscounted future net cash flows.

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs and future inflation levels.

The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment.

Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections.

Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available.

The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.

In 2025, the Company recognized a pretax non-cash impairment charge of $115.0 million ($92.0 million excluding NCI) to reduce the carrying value at the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation.

In 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties. The Company recognized impairments of $34.5 million, related to the Calliope field, and $28.4 million, related to the Nearly Headless Nick field, both in the Gulf of America. Both impairment charges were due to subsurface issues that led to reserve reductions.

See also Note D for further discussion of impairment charges.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company; and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

The Company has deferred tax assets mostly relating to U.S. net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant and equipment.

The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduces such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and negative evidence. Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.

As of December 31, 2025 the Company had a U.S. deferred tax asset associated with net operating losses of $225.0 million. In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for oil and natural gas, (b) estimated reserves for oil and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.

Accounting for retirement and postretirement benefit plans – Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of 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. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields as of December 31, 2025, the Company has used a weighted average discount rate of 5.40% at year end 2025 for the primary U.S. plans. This weighted average discount rate is 0.2% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 7.70% for the primary U.S. plan and periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2026 are expected to be $0.4 million lower than in 2025 primarily due to higher actual return on plan assets, partially offset by an increase in the benefit obligations at December 31, 2025 compared to the prior year.

In 2025, the Company paid $25.1 million into various retirement plans and $12.9 million into postretirement plans. In 2026, the Company is expecting to fund payments of approximately $24.5 million into various retirement plans and $4.7 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.

Recent Accounting Pronouncements

See Note B in our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans and other long-term liabilities. Total payments due after 2025 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.

1 Capital expenditures, drilling rigs and other includes $28.1 million, $25.4 million, $7.7 million, $1.0 million and $0.6 million in 2026 for approved capital projects in non-operated interests in the Gulf of America, the Eagle Ford Shale, Canada Offshore, Brunei, and Canada Onshore, respectively.

Also includes $72.2 million (2026), $141.1 million (2027 - 2028), $81.0 million (2029 - 2030) and $235.9 million (After 2030) for pipeline transportation commitments in Canada.

Also includes $3.7 million (2026), $7.5 million (2027 - 2028), $7.4 million (2029 - 2030) and $14.3 million (After 2030) for long-term take-or-pay commitments relating to natural gas processing in Canada.

Also includes $23.6 million (2026), $47.1 million (2027 - 2028), $48.1 million (2029 - 2030) and $176.8 million (After 2030) for the purpose of supporting future production activities in Vietnam.

2 Other long-term liabilities includes debt interest and future cash outflows for ARO liabilities.

The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that require future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $211.8 million as of December 31, 2025.

Subsequent to the balance sheet date, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In January 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its 6.500% senior notes due 2034 (2034 Notes), used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. See Note F for additional information.

Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Canada Onshore transportation and processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.