MUR 10-K & 10-Q changes, risk factors and insider trading

The Company faces risks in the normal course of business and through global, regional and local events that could have an adverse impact on its reputation, operations, and financial performance. The Board exercises oversight of the Company’s enterprise risk management program, which includes strategic, operationaloperational, cybersecurity and financial matters, as well as compliance and legal risks. The Board receives updates annually on the risk management processes.

Volatility in the global prices of crudeoil oil,and natural gas and NGLs can significantly affect the Company’s operating results, cash flows and financial condition.

Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crudethe oil and natural gashydrocarbons that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:

•worldwide and domestic supplies of, and demand for,for crudeoil oil,and natural gas and NGLs;

•the production levels of non-OPEC countries, including, amongstamong others, production levels in the North American shale plays in the U.S.;

•political instability or armed conflict in oil and natural gas producing regions, such as the Russia-Ukraine conflict and Israeli-Palestinian conflictconflicts and political instability in Venezuela and Iran;

•the level of drilling, completion and production activities by other exploration and productionE&P companies, and variability therein, in response to market conditions;

•technological advancesadvances, such as artificial intelligence (AI) and data center development, affecting energy consumption and energy supply;

West Texas Intermediate (WTI) crude oil prices averaged $75.72$64.81 per BBLbarrel in 2024,2025, compared to $75.72 in 2024 and $77.62 in 2023 and $94.23 in 2022.2023. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect WTI prices. The most common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH),Magellan East Houston, Heavy Louisiana Sweet (HLS) and Brent.

The average New York Mercantile Exchange (NYMEX) natural gas sales price was $2.24$3.54 per million British Thermal Units (MMBTU) in 2024,2025, compared to $2.24 in 2024 and $2.53 in 2023 and $6.38 in 2022.2023. The Company also has exposure to the Canadian benchmark natural gas price, Alberta Energy Company (AECO), which averaged C$1.46C$1.68 per thousand cubic feet (MCF) in 2024,2025, compared to C$1.46 in 2024 and C$2.64 in 2023 and C$5.31 in 2022.2023. The Company has entered into certain forward fixed price contracts as detailed in the “Outlook” section beginning on page 5152 and spot contracts providing exposure to other market prices at specific sales points such as Malin (Oregon, U.S.) and Dawn (Ontario, Canada).

Lower prices, should they occur, will materially and adversely affect our results of operations, cash flows and financial condition. Lower oil and natural gas prices could result from, among other things, increased exports from producers in Venezuela, Russia or the Middle East following resolution of conflicts or political instability in such regions. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize, which could impact the recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods.

The Company, from time to time, enters into various contracts to protect its cash flows against lower oil and natural gas prices. To the extent that the Company enters into these contracts and in the event that prices for oil and natural gas increase in future periods, the Company willmay not fully benefit from the price improvement on all production. See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices.

The Company drills exploratory wells which subject its exploration and productionE&P operating results to exposure to dry hole expense, which has in the past, and may in the future, adversely affect our results of operations. The Company plans to continue assessing exploration activities as part of its overall strategy. In 2024,2025, the Company participated in fourfive exploration wells. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 and the Hai Su Vang-1XVang-2X (Golden Sea Lion), Block 1515-2/2-1717 exploration wells, in Vietnam, resulted in commercial discoveries, while the Civette-1X (Block CI-502) exploration well, located in offshoreCôte Vietnam,d’Ivoire, anddid not encounter commercial hydrocarbons. Subsequent to year end, the non-operated OcotilloBanjo #1 (Mississippi Canyon 40385) and Cello #1 (Mississippi Canyon 385) exploration well, locatedwells, in the Gulf of America, resulted in commercial discoveriesdiscoveries. whileThe theCompany’s Sebastian2026 #1 (Mississippi Canyon 387)exploration and non-operatedappraisal Orangeprogram #1capital (Mississippiexpenditures Canyon 216) wells, located in the Gulfguidance of America, did not encounter commercial hydrocarbons. Additionally, the Company expensed previously suspended costs associated with the Hoffe Park #1 (Mississippi Canyon 166) well which was determined to be non-commercial. The Company has budgeted $145$320 million for its 2025 exploration program, which includes drilling three wells in Vietnam and two wells in Vietnam,Côte twod’Ivoire. One of these exploration wells in theCôte Gulfd’Ivoire, ofCaracal-1X America,(Block CI-102), was completed in February 2026, and onewill wellbe inplugged Côteand d’Ivoire.abandoned as a dry hole after encountering non-commercial hydrocarbon shows.

Murphy continually depletes its oil and natural gas reserves as production occurs. To sustain and grow its business, the Company must successfully replace the oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production. The Company must find, acquire or develop, and produce reserves at a competitive cost to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and productionE&P business, therefore, is dependent on its ability to find (and/or acquire), develop and produce oil and natural gas reserves at costs that are less than the realized sales price for these products.

Proved reserves of crude oil, natural gas and NGLs included in this report on pages 106111 through 115120 have been prepared according to the SEC guidelines by qualified company personnel or qualified independent engineers based on an unweighted average of crudeoil oil,and natural gas and NGL prices in effect at the beginning of each month of the respective year as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs. Estimates of economically recoverable oil and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. In 2025, 95.8% of the proved reserves were audited by third-party auditors.

ItemSome 1A.of RiskMurphy’s Factorsdevelopment -projects Continuedentail significant capital expenditures and have long development cycle times. As a result, the Company’s partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. Murphy’s partners are also susceptible to certain of the risk factors noted herein, including, but not limited to, commodity prices, fiscal regime changes, government project approval delays, regulatory changes, credit downgrades and regional conflict. If one or more of these factors negatively impacts a project operator’s or partners’ cash flows or ability to obtain adequate financing, or if an operator of our projects fails to adequately perform operations or fulfill its obligations under the applicable agreements, it could result in a delay or cancellation of a project, resulting in a reduction of the Company’s reserves and production, which negatively impacts the timing and receipt of planned cash flows and expected profitability.

Murphy’s business is subject to operational hazards, severe weather events, physical security risks and risks normally associated with the exploration and productionE&P of oil and natural gas, which could become more significant as a result of climate change.

The risks associated with hydraulic fracturing operations include, but are not limited to, underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or groundwater contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or groundwater contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses, and third-party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the wastewater from oil and natural gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of wastewater, or any further restrictions placed on wastewater, could curtail the Company’s operations due to regulatory initiatives or natural constraints such as drought or otherwise result in operational delays or increased costs.

The Company’s operations are subject to various international, foreign, national, state, provincial and local environmental, health and safety laws, regulations, governmental actions and permit requirements, including related to 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. The laws, regulations, governmental actions and permit requirements are subject to frequent change and have tended to become stricter over time and at times may be motivated by political considerations. They can impose permitting and financial assurance obligations, as well as operational controls and/or siting constraints on our business, and can result in additional capital and operating expenditures. For example, in March 2024, the U.S. EPA published itsNew finalSource rulePerformance Standards and Emissions Guidelines for the oil and gas industry 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 U.S.EPA. EPA.However, in December 2025, the EPA issued a final rule extending several compliance deadlines and timeframes associated with the new rules. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. The charge, referred to as the WEC, is a component of the Biden Administration’s Methane Emissions Reduction Program to limit methane emissions from the oil and gas industry under the IRA of 2022. In March 2025, however, this rule was disapproved by a joint Congressional resolution, and the OBBBA passed in July 2025 extended the imposition of the WEC until 2034. In addition, it is possible in the future that certain regulatory bodies such as the Railroad Commission of Texas may enact regulation that bans or reduces flaring for U.S. Onshore operations, and certain regulatory bodies in Canada may decide to revoke permits or pause the issuance of permits as a result of non-compliance with, or litigation related to, environmental, health and safety laws and regulations. Compliance with such regulations could result in capital investment or operating costs which would reduce the Company’s net cash flows and profitability.

The Company primarily uses hydraulic fracturing in the Eagle Ford Shale in South Texas and in the Kaybob Duvernay and the Tupper Montney in Western Canada. Texas law imposes permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations, as well as public disclosure of certain information regarding the components used in the hydraulic fracturing process. Regulations in the provinces of British Columbia and Alberta also govern various aspects of hydraulic fracturing activities under their jurisdictions. It is possible that Texas, other states in which we may conduct fracturing in the future, the U.S., Canadian provinces and certain municipalities may adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected, or its costs of drilling and completion could be increased. Once new laws and/or regulations have been enacted and adopted, the costs of compliance are appraised.

In addition, the BOEM and the BSEE have regulations applicable to lessees in federal waters that impose various safety, permitting and certification requirements applicable to exploration, development and production activities in the Gulf of America, and also require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met. These include, in the Gulf of America, well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. Under applicable requirements, BOEM evaluates the financial strength and reliability of lessees and operators active on the U.S. Outer Continental Shelf. If the BOEM determines that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance.

In addition, various executive orders by the Biden Administration and the Department of Interior over the course of 2021 regarding a temporary suspension of normal-course issuance of permits for fossil fuel development on federal lands and a pause on new oil and natural gas leases on public lands and offshore waters, and the Secretary of the Interior’s overhaul of permitting and leasing regulations and rates, finalized in April 2024, could adversely impact Murphy’s operations. While certain aspects of the April 2024 final rule remain in effect, the OBBBA reversed the increases to royalty rates and increased U.S. lease sales both onshore and offshore. Further in May 2025, the Department of Interior announced a policy update designed to expedite oil and gas leasing on onshore public lands. These developments demonstrate the uncertainty regarding the regulation of oil and natural gas related to shifts in political power in the U.S. For further details, see “Risk Factors – General Risk Factors – Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.”

Opposition toward oil and natural gas drilling, development, and production activity has been growinggrown globally. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and nongovernmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti‑development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development ordevelopment, onshore hydraulic fracking.fracking, and construction of pipelines for oil and natural gas.

We may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets and objectives we announce, our methodologies and timelines for pursuing them and related disclosures. If our sustainability practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets and objectives, to comply with ethical, environmental or other standards, regulations or expectations or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation. In recent years, certain stakeholders and regulators have also proposed “anti-ESG” policies, legislation or initiatives. This

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding requirements may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company periodically renews these financing arrangements based on foreseeable financing needs or as they expire. Subsequent to year end, in January 2026, the Company entered into an amendment (the “Second Amendment”) to its credit agreement governing a $2.00 billion senior unsecured guaranteed revolving credit facility (Amended RCF) with a maturity date in January 2031. As of December 31, 2025, the Company had $100 million outstanding borrowings under the previous senior unsecured guaranteed revolving credit facility (RCF). See Note F for further details on the RCF.

Further, changes in investors’ sentiment or view of risk of the exploration and productionE&P industry, including as a result of concerns over climate change, could adversely impact the availability of future financing. Specifically, certain financial institutions (including certain investment advisors and sovereign wealth, pension and endowment funds), in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have elected to shift some or all of their investments away from fossil fuel-related sectors, and additional financial institutions and other investors may elect to do likewise in the future. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and natural gas sector, which, in turn, could adversely impact our cost of capital.

We may be unable to meet our capital allocation frameworkplan of returning a percentage of adjusted free cash flow (FCF) to shareholders through share repurchases and potential dividend increases, which could decrease expected returns on an investment in our common stock.

Our capital allocation frameworkplan includes returning a percentage of adjusted free cash flowFCF to shareholders through share repurchases and potential dividend increases. We may, from time to time, redeem, repurchase, retire or otherwise acquire our outstanding debt through privately negotiated transactions, open market purchases, redemptions, tender offers or otherwise, but we are under no obligation to do so. There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.

In connection with our capital allocation framework,plan, the Board authorized a share repurchase program, as described in this Form 10-K report. Share repurchases and dividends are authorized and determined by the Board at its sole discretion and depend upon a number of factors, including available liquidity, market conditions, applicable legal requirements and other factors. We can provide no assurance that we will make share repurchases or pay dividends in accordance with our capital allocation framework,plan, or at all. Any elimination of, or downward revision in, our share repurchase program, dividend payment plans, or capital allocation frameworkplan could have an adverse effect on the market price of our common stock.

Meeting our capital allocation frameworkplan strategy requires us to generate consistent adjusted free cash flowFCF and have available capital in the years ahead in an amount sufficient to enable us to maintain a conservative capital structure and liquidity position and invest in organic and inorganic growth, as well as to return a significant portion of the cash generated to shareholders through share repurchases and potential dividend increases. The amount of adjusted free cash flowFCF returned in any quarter during the year may vary and may be more or less than our capital allocation framework.plan. We may not meet this goal if we use our available cash to satisfy other priorities, if we have insufficient funds available to repurchase shares or pay dividends, or if the Board determines to change or discontinue share repurchases or dividend payments.

A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.Sheets.

The Company often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and productionE&P activities due to high oil and natural gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and natural gas industry. In addition, periods of inflationary pressure in the wider economy, as seen during 2022, can also lead to a similar increase in the cost of goods and services for the Company. Murphy has a dedicated department 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,Further, 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 prices.

The future impact of any health epidemic, pandemic (such as COVID-19) or similar outbreak cannot be predicted, and any resurgence of disease may cause additional volatility in commodity prices. See “Risk Factors - Price Risk Factors – Volatility in the global prices of crudeoil oil,and natural gas and NGLs can significantly affect the Company’s operating results.results, cash flows and financial condition.”

If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with an epidemic, pandemic or similar outbreak, our operations will likely be impacted and our ability to produce oil,oil and natural gas and NGLs will likely decrease. We may be unable to perform fully on our commitments, and our costs may increase as a result of such epidemic, pandemic or similar outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.

We are subject to income- and non-income-based taxes in the U.S. under federal, state and local jurisdictions and in the foreign jurisdictions in which we operate. Tax laws and regulations, or their interpretation, and administrative practices in various jurisdictions may be subject to significant change, with or without advance notice, due to economic, political and other conditions, and significant judgment is required in evaluating and estimating our provision and accruals for these taxes. Our tax liabilities could be affected by numerous factors, such as changes in tax, accounting and other laws, regulations, administrative practices, principles and interpretations, the mix and level of earnings in a given taxing jurisdiction or our ownership or capital structure. In recent years, multiple domestic and international tax proposals have been introduced that, if enacted into law would impose greater tax burdens on certain multinational enterprises. For example, the Organization for Economic Co-operation and Development (OECD) continues to advance proposals or guidance in international taxation, including the establishment of model rules for a new 15% global minimum tax on certain multinational enterprises, also known as Pillar Two. ManyIn countriesJune have2025, implementedthe orU.S. arereached an understanding with the Group of Seven (G7) members that the U.S. would remove a proposed retaliatory tax from the OBBBA in theexchange processfor an exclusion of implementingU.S. theseparented modelgroups rules.from certain aspects of Pillar Two. This understanding was non-binding and included only the G7 states. However, the OECD released significant administrative guidance on January 5, 2026, which is intended to resolve uncertainty regarding how Pillar Two will apply to U.S. parented groups. In this regard, the administrative guidance introduced a safe harbor that should effectively deem the U.S. tax system to be compliant with Pillar Two and therefore exempt U.S. parented groups from the scope of certain taxes, which should simplify ongoing compliance for affected enterprises. While we do not currently expect that Pillar Two will have a material impact on our results of operations, we continue to monitor the impact as countries implement legislation and the OECD provides additional guidance.guidance Inand addition,countries implement legislation. Further, the IRA,OBBBA, enacted in the U.S. on AugustJuly 16,4, 2022,2025, imposes several new taxes that were effective in 2023, including, but not limited to,includes a 15%broad corporaterange book minimumof tax forreform taxpayersprovisions withaffecting adjusted financial statement income exceeding an average of $1 billion over a three-year testing period and a 1% excise tax on certain stock repurchases made after December 31, 2022.corporations. We continue to analyze the potential impact of the IRAOBBBA on our consolidated financial statements and to monitor guidance issued by the U.S. Department of the Treasury. It is possible that further changes may be enacted to U.S. and international tax rules and regulations, including the U.S. corporate tax system, which could have a material effect on our consolidated cash taxes in the future.

Due to significant shifts in demographics impacting the industry, such as an aging workforce and decreased enrollment in relevant fields, Murphy and industry peers are experiencing challenges in sourcing and developing a pipeline of talent for the foreseeable future, which could place our oil and natural gas exploration, development, and production activities at risk. Furthermore, the cost to attract and retain technical talent has increased in recent years due to competition and may continue to increase if the pool of available talent continues to shrink due to these demographic shifts. If there is a significant decrease in the availability of qualified talent, our operations, cash flows, and financial condition may be materially and adversely impacted.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct exploration, development, and production activities. We are no exception to this trend. As a company, we depend on these technologies to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate internally and externally, and conduct many other business activities.

Maintaining the security of our technology and data and preventing breaches is critical to our business operation. We rely on our information systems,systems and our cybersecurity trainingcontrols, training, and policies,policies to protect and secure information technology (IT), operational technology (OT), including industrial control and supervisory control and data acquisition systems and the intellectual property, strategic plans, customer information, and personally identifiable information of both our employees and our customers.customers contained within those information systems.

A digital infrastructure failure or a successfully executed, undetected cyberattack could significantly disrupt business operations. For example, it might lead to downtime, revenue loss, diversion of management or work force attention, and increased costs for remediation. Additionally, the compromise, theft, or unauthorized release of critical data could damage our reputation, weaken our competitive edge, negatively impact our financial stabilitystability, and expose us to legal risk in multiple jurisdictions. Due to the sophisticated nature of cyberattacks, breaches to our systems could go undetected for a prolonged period of time. Nevertheless,Additionally, evenwe are increasingly vulnerable to cybersecurity incidents originating within our supply chain, including compromises of third-party vendors, software providers, cloud platforms, and other external partners whose environments we depend on. Even if we successfully defend our own digital infrastructure, weweaknesses alsoor relybreaches within these third-party environments could compromise our data, disrupt our operations, harm our individuals, have a material financial impact on the business, or create attack paths into our customers and suppliers, with whom we may share data and services, to protect their digital infrastructure and services from cybersecurity incidents.systems.

As the sophistication of such cyber threats continues to evolve, including through the use of artificial intelligence,AI, we maywill likely be required to dedicate additionalfurther resources to continue to modify or enhance our security measures, or to investigate and remediate any discovered vulnerabilities to cyberattacks. In addition, laws and regulations governing, or proposed to govern, cybersecurity, data privacy and protection and the unauthorized disclosure of confidential or protected information, including legislation in domestic and international jurisdictions, pose increasingly complex compliance challenges and potentially elevate costs, and any actual or perceived failure to comply with these laws and regulations could result in significant penaltiespenalties, fines, judgments, reputational harm and legal liability. Additionally, new regulations or legislation may affect our current uses of protected information and require us to modify how we collect, protect, processprocess, or disclose such information.

We are incorporating artificial intelligenceAI technologies into our processesprocesses, and these technologies may present business, compliance, and reputational risks.

Our business increasingly utilizes artificialAI intelligence (“AI”),and machine learning,learning to automate certain tasks and automated decision making to improve our internal processes. Issues in the development and use of AI, combined with an uncertain regulatory environment, may result in new or enhanced governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability or other adverse consequences to our business operations, all of which could adversely affect our business, financial conditioncondition, and results of operations.

The use of AI can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or generating content that appears correct but is factually inaccurate, misleading, or otherwise flawed, which could expose us to risks related to inaccuracies or errors in the output of such technologies. Additionally, emerging forms of autonomous (or semi-autonomous) AI tools, such as AI agents capable of independently executing tasks, interacting with systems, or initiating actions, present additional risks such as unauthorized access, sensitive data leakage or unintended operational impacts. The use of unapproved AI tools within the organization further increases the risk of security incidents, compliance failures, and exposure of sensitive information. It is not possible to predict all of the risks related to the use of AI, machine learninglearning, and automated decision making,automation, and developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations may adversely affect our ability to develop and use such technologies or subject us to liability.

Prices and availability of crude oil, natural gas and refined products could be influenced by political factors and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax law changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and natural gas leases, restrictions on drilling and/or production, tariffs, restraints and controls on imports and exports, safety, and relationships between employers and employees. For example, in 2025, the Trump Administration has proposedannounced additional tariffs on Canadagoods from all countries pursuant to the International Emergency Economic Powers Act. These tariffs were later found to have exceeded presidential authority and Mexico.were invalidated by the courts. Following such ruling, President Trump implemented a 150-day “global tariff” of 10% effective February 24, 2026, using presidential powers under the Trade Act of 1974, and indicated a desire to increase such “global tariff” to 15% and to seek to extend such tariffs under other statutes. Such tariffs may put upwards pressure on the prices of goods and services across the jurisdictions in which we operate,operate. whichIn couldaddition, reducethe ourscope abilityand todurability offerof competitiveexisting pricingand tofuture potentialtariff customers.measures remain uncertain. We cannot predict whatfuture changes to trade policy will be made by the Trump Administration, the U.S. Congress or other governments,policy, including whether existing or future tariff policies will be maintained or modified or whether the entry into new bilateral or multilateral trade agreements will occur, nor can we predict the effects that any such changes would have on our business. Changes in trade policy have resulted and could again result in reactions from trading partners, including adopting responsive trade policies making it more difficult or costly for us to conduct business across the jurisdictions in which we operate. SuchThese changes in trade policy or in laws and policies governing foreign trade,changes, and any resulting negative sentiments asor aretaliatory resulttrade of such changes,practices, could materially and adversely affect our business, financial condition, results of operations and liquidity. Governments could also initiate regulations concerning matters such as currency fluctuations, currency conversion, protection and remediation of the environment, and concerns over the possibility of global warming caused by the production and use of hydrocarbon energy. As of December 31, 2024,2025, 1.7%1.8% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada.

Murphy Oil Corporation is a worldwide oil and natural gas exploration and productionE&P company with both onshore and offshore operations and properties. The Company produces crudeoil oil,and natural gas and NGLs primarily in the U.S. and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide. A more detailed description of the Company’s significant assets can be found in “Item 1” of this Form 10-K report.

•Generated net income of $486.5$138.8 million ($407.2$104.2 million excluding NCI) and net cash provided by operating activities of $1,729.0$1,247.8 million;

◦•Repurchased 8.03.6 million shares of common stock under the share repurchase program for $300.0$100.0 million ($302.7$100.8 million including excise taxes and fees) under the capital allocation plan1;

1 Details of the capital allocation frameworkplan can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024. The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock.

Murphy’s continuing operations generate revenue by producing crudeoil oil,and natural gas and NGLs in the U.S. and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of crudeoil oil,and natural gas and NGLs.gas. In order to make a profit and generate cash in its exploration and productionE&P business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

1 The Company has presented its former U.K., MalaysiaU.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

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

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

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

43 Proved reserves at December 31, 2024,2025, 20232024 and 2022,2023, include 15.915.0 MMBOE, 15.515.9 MMBOE and 18.215.5 MMBOE, respectively, relatingattributable to noncontrolling interest.NCI.

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

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

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:follows.

Lease operating expenses and transportation, gathering and processing expenses in 20242025 increaseddecreased by $152.6$171.8 million and decreased by $22.2$11.1 million, respectively, compared to 2023.2024. HigherLower lease operating expenses were primarily due to lower workover costs in the Gulf of America, particularlylower atoperating thecosts Samuraias anda Neidermeyer fields, and the restartresult of the non-operatedacquisition Terra Nova field in Canada Offshore inof the first quarter of 2024. These werePioneer

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued partially offset by lower production handling fees and lower overall volumes. Lower transportation, gathering and processing expenses were primarily due to lower volumes.

The Company’s depreciation, depletion and amortizationDD&A expense by geographic area was as follows:follows.

Depreciation, depletion and amortization expense (DD&A) in 20242025 increased by $6.4$112.5 million compared to 2023.2024. HigherThe DD&Aincrease was primarily thedue result ofto higher sales volumes at the non-operated Terra Nova field in Canada Offshore and higher rates atin the Eagle Ford ShaleShale, andhigher rates in the Gulf of America, and was partially offset by lower volumesproduction in the Gulf of America and lower rates and volumes at Kaybob Duvernay.America.

In 20242024, the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million. In the first quarter of 2024,quarter, the Company recognized an impairment expense of $34.5 million for the Calliope field. In the fourth quarter of 2024,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.

TheExploration Company’s exploration expenses were as follows:Expenses

Exploration expenses in 20242025 decreased by $101.3$21.8 million compared to 2023.2024. 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. InThe 2023,decrease dry holes and previously suspended exploration costs relateddue to previously suspended exploration costs for the Cholula-1EXP well in offshore Mexico andlower dry hole costs forwas partially offset by increases to geological, geophysical and other exploration costs, related to the Chinook #7 (Walker Ridge 425) exploration well and the non-operated Oso #1 (Atwater Valley 138) exploration well in theCompany’s Gulf of America,America bothand ofCôte whichd'Ivoire encounteredexploration non-commercial hydrocarbons.programs.

Income taxes were $106.3$90.2 million in 2024,2025, a decrease of $131.5$16.1 million compared to 2023.2024. Lower income taxes were primarily the result of lower pretax income,income. andThis was partially offset by the non-recurrence of an income tax deduction forthat occurred in 2024 relating to prior years’ AustraliaAustralian exploration spend (see Note H).spend.

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of oilnatural gas 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$158.4 million in 2024,2025, aan favorableunfavorable variance of $46.9$49.3 million compared to 2023.2024. The favorableunfavorable 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 compared to foreign exchange loss of $10.7 million in 2023, primarily2024, as a result of unrealized exchange rate changes relating to our Canadian subsidiary. InterestThis increase was partially offset by lower interest charges are lower in 2024 primarily2025 due to lower overallno debt levels.repayment Thefees lowerin the current year, and a higher income tax benefit wasattributable theto our Canadian segment as a result of alarger lowercurrent-period current period losslosses before income tax.taxes, primarily as a result of foreign exchange.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarterperiod ended MarchJune 31,30, 2026 included under “Item 1. Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2025. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.

Significant Company financial and operational highlights during the firstsecond quarter of 2026 were as follows:

•IncreasedProduction productionwas to 180,053175,013 barrels of oil equivalent (BOE) per day (including NCI), upa decrease from 163,374196,315 BOE per day in the firstsecond quarter of 2025;

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended MarchJune 31,30, 2026,2026 was $69.2$264.0 million compared to net income of $90.1$33.8 million for the same period in 2025. The resultsincrease forin 2026 werewas impactedprimarily by higher exploration expense ($68.3 million), higher depreciation, depletion and amortization expenses (DD&A) ($60.2 million), and higher income tax expense ($17.2 million) and were partially offsetdriven by higher revenues from production ($59.6$243.3 million), lower lease operating expenses ($61.6$71.8 million), higher other income ($43.6 million), and lower lossestransportation, fromgathering derivativeand instrumentsprocessing expenses ($9.5$8.8 million). These favorable items were partially offset by higher income tax expense ($76.0 million), higher exploration expense ($28.9 million), and higher other operating expenses ($12.9 million).

For the three months ended MarchJune 31,30, 2026,2026 total hydrocarbon production was 180,053175,013 barrels of oil equivalent per day, ana increasedecrease of 10%11% compared to the firstsecond quarter of 2025. The increasedecrease was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in the Gulf of America.America, Higherprimarily attributable to planned and unplanned downtime at multiple fields, partially offset by higher production in theCanada Offshore. Higher Canada Offshore production was driven by increased production at Terra Nova and Hibernia, while higher Canada Onshore production was driven by new wells at Kaybob. Higher Eagle Ford Shale and Canada Onshoreproduction was primarily the result of new wells online in the current year at Karnes and Catarina in the U.S., and at Tupper Montney in Canada. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.year.

Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

At MarchJune 31,30, 2026, the West Texas Intermediate (WTI) crude oil futures price werewas $82.75$68.96 per barrel, whereas the crude oil futures price at the end of AprilJuly 2026 was $90.56,$80.31, reflecting a 9%16% increase in price. As of MayAugust 4,3, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $93.58$76.97 per barrel. Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.

The following table contains the weighted average sales prices for the three-monththree periodsand six months ended MarchJune 31,30, 2026 and 2025:

The following table contains benchmark prices relevant to the Company for the three-monththree periodsand six months ended MarchJune 31,30, 2026 and 2025:

The following table contains hydrocarbons produced during the three-monththree periodsand six months ended MarchJune 31,30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.32.

The following table contains hydrocarbons sold during the three-monththree periodsand six months ended MarchJune 31,30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.32.

DD&A for the threesix months ended MarchJune 31,30, 2026 increased by $60.2$62.3 million.million compared to the same period in 2025. Higher DD&A in the current quarter iswas primarily duedriven toby significantly higher sales volumes onshorein U.S.the Eagle Ford Shale from new Alice May wells at Karnes and onshorenew Canada,wells asat wellCatarina, ascombined with higher rates in the Eagle Ford Shale and the Gulf of America,America. andAdditionally, washigher sales volumes at Kaybob from new wells contributed to the increase. These items were partially offset by lower sales volumes offshorein U.S.the Gulf of America and offshoreat Canada.Tupper.

Exploration expenses for the three months ended MarchJune 31,30, 2026 increased by $68.3$28.9 million compared to the same period in 2025. Higher exploration expenses in the current quarter were largely drivendue byto higherexploration dryactivities holein Côte d’Ivoire, Vietnam, and the Gulf of America. Dry holes and previously suspended exploration costs primarily related to the Civette-1XHai Su Vang-4X (Golden Sea Lion) appraisal well (Block CI-50215-2/17) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons.Vietnam.

Income taxes for the three and six months ended MarchJune 31,30, 2026 increased by $13.9$61.4 million and $75.4 million, respectively, compared to the same periodperiods in 2025. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, higher exploration expenses, mainly due to dry hole expenses recognized related to Côte d’Ivoire, did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.

The Corporate segment reported a loss of $36.4$32.0 million for the three months ended MarchJune 31,30, 2026,2026 a favorable variance of $11.8$23.9 million,million compared to the same period in 2025. The favorable variance was primarily due to no losses on derivative instruments ($9.5 million) in the current quarter and higher foreign exchange gains ($8.8$44.0 million)., driven by favorable currency movements in Canada. These changesgains were partially offset by higherno interestrepeat expenseof gains on derivative instruments in 2026 ($5.3$10.3 million) and lower income tax benefit ($14.5 million) due to costshigher relatedcurrent toperiod thenet redemption of the 2027 Notes and 2028 Notes.income.

Net cash provided by continuing operations activities for the threesix months ended MarchJune 31,30, 2026 wasincreased $20.5by $318.4 million higher compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized pricescommodity andprices, volumeswhich resultingresulted in highera $302.9 million increase in revenue from production ($59.6 million)production, and lower lease operating expenses ($61.6$133.4 million),. These favorable impacts were partially offset by thea timing of net non-cash working capital ($85.2$65.1 million) and changesdecrease in other operating activities, net ($18.7 million),net, primarily duerelated to fluctuationscontract prepayments in Vietnam and foreign exchange ratesrate ($8.9fluctuations, as well as a $48.4 million) andunfavorable change in net non-cash working capital, which was also affected by higher expenditurescommodity for asset retirements ($8.8 million).prices.

Net cash required by investing activities for the threesix months ended MarchJune 31,30, 2026 was $40.7$210.2 million higher compared to the same period in 2025. The increase was primarily due to higher acquisition capital ($21.3 million) and higher property additions and dry hole costs ($19.4$188.1 million) and higher acquisition capital ($22.1 million).