MURPHY OIL CORP

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

Revenues from production in 2024 decreased by $361.7 million compared to 2023. Revenue was lower in the Gulf of America, mostly driven by downtime for workovers, hurricane-related downtime and timing of new wells. Eagle Ford Shale revenues decreased due to timing and performance of wells brought online. These decreases were partially offset by wells brought back online in the fourth quarter of 2023 at non-operated Terra Nova. Lower pricing across all products also contributed to the decrease during the period.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. “Sales of purchased natural gas” is included in “Total revenues and other income” and “Costs of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 33. Sales of purchased natural gas during 2024 were $3.7 million.

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 2024 increased by $152.6 million and decreased by $22.2 million, respectively, compared to 2023. Higher lease operating expenses were primarily due to workover costs in the Gulf of America, particularly at the Samurai and Neidermeyer fields, and the restart of the non-operated Terra Nova field in Canada Offshore in the first quarter of 2024. These were partially offset by lower production handling fees and lower overall volumes. Lower transportation, gathering and processing expenses were primarily due to lower volumes.

Depreciation, Depletion and Amortization Expense

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

Depreciation, depletion and amortization expense (DD&A) in 2024 increased by $6.4 million compared to 2023. Higher DD&A was primarily the result of higher volumes at the non-operated Terra Nova field in Canada Offshore and higher rates at Eagle Ford Shale and in the Gulf of America, and was partially offset by lower volumes in the Gulf of America and lower rates and volumes at Kaybob Duvernay.

Impairment of Assets

In 2024 the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million. In the first quarter of 2024, the Company recognized an impairment expense of $34.5 million for the Calliope field. In the fourth quarter of 2024, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field. Both fields were impaired as a result of operational issues that led to reserve reductions.

There were no impairments recorded in 2023.

Exploration Expenses

The Company’s exploration expenses were as follows:

Exploration expenses in 2024 decreased by $101.3 million compared to 2023. In 2024, dry holes and previously suspended exploration costs primarily related to the Sebastian #1 (Mississippi Canyon 387) exploration well, the non-operated Orange #1 (Mississippi Canyon 216) exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America. In 2023, dry holes and previously suspended exploration costs related to previously suspended exploration costs for the Cholula-1EXP well in offshore Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well and the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America, both of which encountered non-commercial hydrocarbons.

Other Expenses

Other expenses were $0.3 million in 2024, a decrease of $56.6 million compared to 2023. Other expenses were lower primarily due to the absence of other operating expenses in Canada related to the non-operated Terra Nova life extension project, lower asset retirement adjustments, no contingent consideration adjustments in the current period and higher interest income received in 2024.

Income Taxes

Income taxes were $106.3 million in 2024, a decrease of $131.5 million compared to 2023. Lower income taxes were primarily the result of lower pretax income, and an income tax deduction for prior years’ Australia exploration spend (see Note H).

Corporate: 2024 vs 2023

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of oil sold) and corporate overhead not allocated to E&P. Realized and unrealized losses on derivative instruments result from increases in market oil and natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $109.1 million in 2024, a favorable variance of $46.9 million compared to 2023. The favorable variance was primarily due to foreign exchange gain of $45.4 million in 2024 compared to foreign exchange loss of $10.7 million in 2023, primarily as a result of unrealized exchange rate changes relating to our Canadian subsidiary. Interest charges are lower in 2024 primarily due to lower overall debt levels. The lower income tax benefit was the result of a lower current period loss before income tax.

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured RCF, as described below. The Company’s liquidity requirements, both in the short-term (2025) and long-term (beyond 2025), 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 2024 was $19.8 million lower compared to 2023. The decrease was primarily attributable to lower revenue from production ($361.7 million) and higher lease operating expenses costs ($152.6 million), partially offset by a decrease due to timing of non-cash working capital ($174.2 million) settlements, no contingent consideration payments related to prior Gulf of America acquisitions in 2024 (2023: $139.6 million), lower exploration expenses ($101.2 million), and changes in other operating activities, net ($56.4 million) primarily due to decreased expenditures for asset retirements.

Payments of contingent consideration in 2023 are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.

During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of America acquisitions. See Note O for further details.

The 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, 2024, and 2023 were $78.8 million and $108.9 million, respectively. Cash interest paid in 2024 was primarily due to interest payments on outstanding debt. Some of these payments related to accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) in the aggregate redemption amount of $650.1 million. In 2023, cash interest paid was higher than 2024, primarily due to higher debt levels in 2023 and accelerated interest payments due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 2027 Notes, the 2028 Notes, and the 2029 Notes for an aggregate redemption amount of $498.2 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2024 was $90.5 million lower compared to 2023. The decrease was primarily due to lower property additions and dry hole costs ($157.9 million) and lower acquisition capital ($35.6 million), partially offset by the absence of proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million).

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 accrual basis capital expenditures are shown below.

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

Capital expenditures in 2024 primarily relate to development drilling and field development activities in the Gulf of America, primarily related to the Mormont, Khaleesi, Lucius, St. Malo and Samurai fields ($306.9 million), at Eagle Ford Shale ($291.8 million), at Tupper Montney and Kaybob Duvernay ($116.3 million), at other international locations ($45.1 million), and at non-operated Hibernia ($18.2 million). In addition, total exploration costs were $153.9 million.

Exploration costs in 2024 were primarily comprised of activities in the Gulf of America related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and non-operated Oso #1 (Atwater Valley 138) exploration wells. Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024. Non-operated Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024. Additional exploratory costs relate to oil discoveries, including the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam, as well as other ongoing projects.

Cash Required by Financing Activities

Net cash required by financing activities in 2024 decreased by $207.2 million compared to 2023. In 2024, cash used in financing activities was principally for the repurchase of common shares ($301.4 million, excluding excise tax). In addition, the Company completed a refinancing transaction whereby new senior notes due 2032 were issued in the aggregate amount of $600.0 million and the proceeds were used for the aggregate repayment and repurchase of $600.0 million of its 2027 Notes, 2028 Notes and 2029 Notes. The Company also repurchased $50.0 million of its 2027 Notes, paid cash dividends to shareholders of $1.20 per share ($180.0 million), and distributed funds to the noncontrolling interest in MP GOM ($118.6 million).

Liquidity

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

The Company’s $1.35 billion senior unsecured RCF expires in October 2029. As of December 31, 2024, the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF. Borrowings under the RCF are subject to certain interest rates. Please refer to Note F for further details. At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68%. At December 31, 2024, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2024, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $95.2 million (2023: $149 million), the majority of which was held in Canada ($58.5 million), Vietnam ($8.7 million) and Brunei ($8.5 million). In addition, approximately $7.8 million and $6.4 million of cash was held in the U.K. and Mexico, respectively. In certain cases, the Company could incur cash taxes or other costs should these cash balances be 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, 2024, net working capital had an unfavorable decrease of $63.2 million compared to December 31, 2023. The decrease was primarily attributable to lower accounts receivable ($71.5 million), higher operating lease liabilities ($45.4 million), higher current ARO liabilities ($37.4 million), and higher accounts payable ($25.3 million), partially offset by a higher cash balance ($106.5 million). Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas, and lower pricing received for all crude oil, natural gas and NGLs. Higher operating lease liabilities are primarily due to an extension of an existing drilling ship lease in the Gulf of America. Higher current ARO liabilities are primarily due to certain Gulf of America obligations to be completed in 2025. Higher accounts payable are due to the timing of payments for certain drilling activities and ongoing workover projects.

Capital Employed

A summary of capital employed as of December 31, 2024 and 2023 follows.

As of December 31, 2024, long-term debt decreased by $53.9 million compared to December 31, 2023, as a result of the repurchase of the 2027 Notes and 2028 Notes. The Company also completed a refinancing transaction whereby it issued $600.0 million of 2032 Notes, and used all of the proceeds to complete the repurchase and redemption, in whole or in part, of the 2027 Notes, 2028 Notes, and 2029 Notes. As of December 31, 2024, the fixed-rate notes had a weighted average maturity of 9.3 years and a weighted average coupon of 6.1%. Refer to Note F for additional details.

Murphy’s shareholders’ equity decreased by $168.5 million in 2024 primarily due to cash dividends paid ($180.0 million), shares repurchased ($302.7 million, including excise tax), and foreign currency translation losses ($134.7 million), partially offset by net income earned ($407.2 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity" on page 70 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 2024, compared to 2023 are discussed below.

Property, plant and equipment, net of depreciation decreased $170.5 million principally due to DD&A expense and foreign exchange rates applicable for the Canadian assets, substantially offset by capital expenditures in the year. Capital expenditures are discussed above in the “Cash Required by Investing Activities” section.

Murphy had commitments for capital expenditures of approximately $417.0 million at December 31, 2024 (2023: $209.8 million). This amount includes $220.0 million for Other Offshore, primarily related to approved expenditures for capital projects relating to interests in Vietnam for the Lac Da Vang (Golden Camel) field development project, $112.2 million at Eagle Ford Shale, primarily at the Karnes field, $53.6 million relating to

Gulf of America interests, primarily at the Mormont and non-operated St. Malo fields, and $31.2 million relating to interests in Canada Onshore, primarily at Kaybob Duvernay.

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

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

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

Deferred income tax liabilities increased $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax 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) and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income excludes certain items that management believes affects the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

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

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

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

1 Excludes amounts attributable to a 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 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 2024 Sustainability Report issued on August 7, 2024, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2024, many countries worldwide continued to experience moderate inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021). The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC and certain non-OPEC members’ production levels and/or attitudes of traders concerning supply and demand in the future. Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.

To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services. However, from time to time,

Murphy 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 possible inflationary pressures in our business.

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

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 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 crude oil, natural gas and NGLs are presented on pages 106 to 115 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, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2024 beginning on pages 4 and 106 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 Sheet 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 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties. In the first quarter of 2024, the Company recognized $34.5 million related to the Calliope field, in the Gulf of America, and in the fourth quarter of 2024, the Company recognized $28.4 million related to the Nearly Headless Nick field, in the Gulf of America. Both of the impairment charges were due to subsurface issues that led to reserve reductions. There were no impairments recognized in 2023.

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, 2024 the Company had a U.S. deferred tax asset associated with net operating losses of $289.6 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 crude oil, natural gas and NGLs, (b) estimated reserves for crude oil, natural gas and NGLs, (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, 2024, the Company has used a weighted average discount rate of 5.63% at year-end 2024 for the primary U.S. plans. This weighted average discount rate is 0.5% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 7.60% 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 2025 are expected to be $5.3 million lower than in 2024 primarily due to the decrease in the benefit obligations at December 31, 2024 compared to the prior year, which decreases the interest cost recognized in net periodic benefit costs.

In 2024, the Company paid $35.5 million into various retirement plans and $13.0 million into postretirement plans. In 2025, the Company is expecting to fund payments of approximately $26.4 million into various retirement plans and $4.2 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 2024 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 $25.3 million, $13.7 million, $7.3 million and $1.1 million, in 2025 for approved capital projects in non-operated interests in the Gulf of America, U.S. Onshore, Canada Offshore and Other Offshore, respectively. Capital expenditures, drilling rigs and other includes $4.7 million in 2026 for approved capital projects in non-operated interests in the Gulf of America.

Also includes $73.1 million (2025), $138.4 million (2026 - 2027), $114.0 million (2028 - 2029) and $256.5 million (After 2029) for pipeline transportation commitments in Canada.

Also includes $3.6 million (2025), $7.1 million (2026 - 2027), $7.1 million (2028 - 2029) and $17.2 million (After 2029) for long-term take or pay commitments relating to natural gas processing in Canada.

Also includes approximately $7.2 million (2025), $25.5 million (2026 - 2027), $25.3 million (2028 - 2029) and $120.0 million (After 2029) for Other Offshore for the purpose of supporting future development activities in Vietnam.

2 Other long-term liabilities, including debt interest, includes 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 $189.7 million as of December 31, 2024.

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.