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What changed in MURPHY OIL CORP's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of MURPHY OIL CORP's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+387 added−369 removedSource: 10-K (2026-02-25) vs 10-K (2025-02-27)

Top changes in MURPHY OIL CORP's 2025 10-K

387 paragraphs added · 369 removed · 216 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

60 edited+10 added−105 removed63 unchanged
Biggest changeThe following table shows the number of oil and natural gas wells producing or capable of producing at December 31, 2024: Oil Wells Natural Gas Wells Gross Net Gross Net United States Onshore 1,221 971 30 5 Offshore 81 37 13 5 Total United States 1,302 1,008 43 10 Canada Onshore 19 13 356 340 Offshore 50 5 — — Total Canada 69 18 356 340 Totals 1,371 1,026 399 350 Murphy’s net wells drilled and completed in the last three years are shown in the following table: United States Canada Other Totals Productive Dry Productive Dry Productive Dry Productive Dry 2024 Exploration 0.3 0.8 — — — — 0.3 0.8 Development 23.9 — 15.3 — — — 39.2 — 2023 Exploration — 1.3 — — — — — 1.3 Development 34.1 — 15.1 — — — 49.2 — 2022 Exploration — — — — — 0.6 — 0.6 Development 29.1 — 22.1 — — — 51.2 — Murphy’s drilling wells in progress at December 31, 2024 are shown in the following table.
Biggest changeUnited States Canada Other Totals Productive Dry Productive Dry Productive Dry Productive Dry 2025 Exploration — — — — 0.8 0.9 0.8 0.9 Development 33.3 — 13.0 — — — 46.3 — 2024 Exploration 0.3 0.8 — — — — 0.3 0.8 Development 23.9 — 15.3 — — — 39.2 — 2023 Exploration — 1.3 — — — — — 1.3 Development 34.1 — 15.1 — — — 49.2 — Murphy’s drilling wells in progress at December 31, 2025 are shown in the following table.
Murphy is currently required to report GHG emissions from its U.S. operations in the Gulf of America and onshore in South Texas and from its Canadian onshore business in British Columbia and Alberta. In Canada, Murphy is subject to GHG regulations and resultant carbon pricing programs specific to the jurisdiction of operation.
Murphy is currently required to report GHG emissions from its U.S. operations in the Gulf of America and onshore in South Texas and from its onshore Canadian business in British Columbia and Alberta. In Canada, Murphy is subject to GHG regulations and resultant carbon pricing programs specific to the jurisdiction of operation.
Further, the EPA amended its GHG Reporting Rule on May 14, 2024 to modify certain calculation methodologies, changes to the general reporting structure, and EPA’s treatment of advanced measurement technologies.
Further, the EPA amended its GHG Reporting Rule on May 14, 2024 to modify certain calculation methodologies, changes to the general reporting structure, and the EPA’s treatment of advanced measurement technologies.
The Board exercises oversight of the Company’s enterprise risk management program, which includes strategic, operational and financial matters, as well as compliance and legal risks. The Board receives updates annually on the risk management processes. The following are some important factors that could cause the Company’s actual results to differ materially from those projected in any forward-looking statements.
The Board exercises oversight of the Company’s enterprise risk management program, which includes strategic, operational, cybersecurity and financial matters, as well as compliance and legal risks. The Board receives updates annually on the risk management processes. The following are some important factors that could cause the Company’s actual results to differ materially from those projected in any forward-looking statements.
Business - Continued All employees’ performance is evaluated at least annually through self-assessments that are reviewed in discussions with supervisors. Employees’ performance is evaluated on various key performance indicators set annually, including behaviors that support our mission, vision, values and contributions toward executing our Company’s goals and business strategy.
All employees’ performance is evaluated at least annually through self-assessments that are reviewed in discussions with supervisors. Employees’ performance is evaluated on various key performance indicators set annually, including contributions toward executing our Company’s goals and business strategy and behaviors that support our mission, vision, values.
We focus on the following factors in order to implement and develop our human capital strategy: • Employee Compensation Programs • Employee Performance and Feedback • Talent Development and Training • Health and Welfare Benefits • Employee Engagement The Board receives related updates from the Vice President, Human Resources and Administration on a regular basis including the review of compensation, benefits, succession and talent development.
We focus on the following factors in order to implement and develop our human capital strategy: • Employee Compensation Programs • Employee Performance and Feedback • Talent Development and Training • Health and Welfare Benefits • Employee Engagement The Board receives related updates from the Senior Vice President, Human Resources, Administration and Communications on a regular basis including the review of compensation, benefits, succession and talent development.
Talent Development and Training Employees are able to participate in continuous training and development, with the goal of equipping them for success and providing increased opportunities for growth. Through our digital platform, My Murphy Learning, employees have access to LinkedIn Learning with more than 10,600 courses, Continuing Education Unit credit and certification opportunities, and access to expert instructors.
Talent Development and Training Employees are able to participate in continuous training and development, with the goal of equipping them for success and providing increased opportunities for growth. Through our digital platform, My Murphy Learning, employees have access to LinkedIn Learning with more than 10,000 courses, Continuing Education Unit credit and certification opportunities, and access to expert instructors.
The U.S. Endangered Species Act was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds, under the Migratory Bird Treaty Act, and marine mammals under the Marine Mammal Protection Act.
Endangered Species Act was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds, under the Migratory Bird Treaty Act, and marine mammals under the Marine Mammal Protection Act.
The Company has entered into certain forward fixed price contracts as detailed in the “ Outlook ” section beginning on page 51 and spot contracts providing exposure to other market prices at specific sales points such as Malin (Oregon, U.S.) and Dawn (Ontario, Canada).
The Company has entered into certain forward fixed price contracts as detailed in the “ Outlook ” section beginning on page 52 and spot contracts providing exposure to other market prices at specific sales points such as Malin (Oregon, U.S.) and Dawn (Ontario, Canada).
Business - Continued Environmental, Social and Governance (ESG) Disclosure Our annual sustainability report is informed by internationally recognized ESG reporting frameworks and standards, including Sustainability Accounting Standards Board, Task Force on Climate-related Financial Disclosures (TCFD), Global Reporting Initiative, Ipieca and American Petroleum Institute.
Environmental, Social and Governance (ESG) Disclosure Our annual sustainability report is informed by internationally recognized ESG reporting frameworks and standards, including Sustainability Accounting Standards Board, Task Force on Climate-related Financial Disclosures (TCFD), Global Reporting Initiative, Ipieca and American Petroleum Institute.
Any limitations or further regulation of GHG, such as a cap and trade system, technology mandate, emissions tax, or expanded reporting requirements, could cause the Company to restrict operations, curtail demand for hydrocarbons generally, and/or cause costs to increase.
Any limitations or further regulation of GHGs, such as a cap and trade system, technology mandate, emissions tax, or expanded reporting requirements, could cause the Company to restrict operations, curtail demand for hydrocarbons generally, and/or cause costs to increase.
Many of the factors influencing prices of crude oil and natural gas are beyond our control.
Many of the factors influencing prices of oil and natural gas are beyond our control.
Price Risk Factors Volatility in the global prices of crude oil, 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 crude oil and natural gas that it produces.
Price Risk Factors Volatility in the global prices of oil and natural gas 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 the hydrocarbons that it produces.
Murphy’s business is subject to operational hazards, severe weather events, physical security risks and risks normally associated with the exploration and production of oil and natural gas, which could become more significant as a result of climate change. The Company operates in a variety of locales, including urban, remote, and sometimes inhospitable, areas around the world.
Murphy’s business is subject to operational hazards, severe weather events, physical security risks and risks normally associated with the E&P of oil and natural gas, which could become more significant as a result of climate change. The Company operates in a variety of locales, including urban, remote, and sometimes inhospitable, areas around the world.
As this is an area of continual improvement across our industry, we strive to update our disclosures in line with operating developments and with emerging best practice ESG reporting standards. In 2024, we published our sixth annual sustainability report, located on the Company’s website, which is not incorporated by reference hereto.
As this is an area of continual improvement across our industry, we strive to update our disclosures in line with operating developments and with emerging best practice ESG reporting standards. In 2025, we published our seventh annual sustainability report, located on the Company’s website, which is not incorporated by reference hereto.
Proved reserves of crude oil, natural gas and NGLs included in this report on pages 106 through 115 have been prepared according to the SEC guidelines by qualified company personnel or qualified independent engineers based on an unweighted average of crude oil, 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.
Proved reserves of crude oil, natural gas and NGLs included in this report on pages 111 through 120 have been prepared according to the SEC guidelines by qualified company personnel or qualified independent engineers based on an unweighted average of oil and natural gas 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.
Health and Safety Murphy’s commitment to safety is strong, and so are our actions to protect our workforce and communities. Our employees are our most valuable asset.
Business - Continued Health and Safety Murphy’s commitment to safety is strong, and so are our actions to protect our workforce and communities. Our employees are our most valuable asset.
See our 2024 Sustainability Report, located on the Company’s website, for details, which is not incorporated by reference hereto.
See our 2025 Sustainability Report, located on the Company’s website, for details, which is not incorporated by reference hereto.
Together with the Executive Leadership Team, the Vice President, Human Resources and Administration, who reports directly to our President and Chief Executive Officer (CEO), is responsible for developing and executing our human capital management strategy.
Together with the Executive Leadership Team, the Senior Vice President, Human Resources, Administration and Communications, who reports directly to our President and Chief Executive Officer, is responsible for developing and executing our human capital management strategy.
This data is shared on a regular basis with our Executive Leadership Team, who use it, in addition to other pertinent data, to develop our human capital strategy. In 2024, our voluntary employee turnover rate, including retirements, was 7%.
This data is shared on a regular basis with our Executive Leadership Team, who use it, in addition to other pertinent data, to develop our human capital strategy. In 2025, our voluntary employee turnover rate, including retirements, was 4%.
Risk Factors - Continued recoverable crude oil, natural gas and NGL 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.
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.
The discounted future net revenues from our proved reserves as reported on pages 119 and 120 should not be considered as the market value of the reserves attributable to our properties.
The discounted future net revenues from our proved reserves as reported on pages 124 and 125 should not be considered as the market value of the reserves attributable to our properties.
During 2024, approximately 21% of the Company’s total production was at fields operated by others, while at December 31, 2024, approximately 14% of the Company’s total proved reserves were at fields operated by others. Some of Murphy’s development projects entail significant capital expenditures and have long development cycle times.
During 2025, approximately 19% of the Company’s total production was at fields operated by others, while at December 31, 2025, approximately 12% of the Company’s total proved reserves were at fields operated by others. Some of Murphy’s development projects entail significant capital expenditures and have long development cycle times.
The Company drills exploratory wells which subject its exploration and production 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, the Company participated in four exploration wells.
The Company drills exploratory wells which subject its E&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 2025, the Company participated in five exploration wells.
West Texas Intermediate (WTI) crude oil prices averaged $75.72 per BBL in 2024, compared to $77.62 in 2023 and $94.23 in 2022. 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.
West Texas Intermediate (WTI) crude oil prices averaged $64.81 per barrel in 2025, compared to $75.72 in 2024 and $77.62 in 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.
This process occurs thousands of feet below the surface and creates fractures in the rock formation within the reservoir which enhances migration of oil and natural gas to the wellbore.
This process occurs thousands of feet below the surface and creates fractures in the rock formation within the reservoir which enhances migration of oil and natural gas to the wellbore. 17 Table of Contents PART I
Human Capital Management At Murphy, we believe in providing energy that empowers people, and that is what our 750 employees do every day. As of December 31, 2024, we had 482 office-based employees and 268 field employees, all of whom are guided by our mission, vision, values and behaviors.
Human Capital Management At Murphy, we believe in providing energy that empowers people, and that is what our 813 employees do every day. As of December 31, 2025, we had 542 office-based employees and 271 field employees, all of whom are guided by our mission, vision, values and behaviors.
We also believe that the well-being of our employees is enhanced when they can give back to their local communities or charities through programs like the Company Matching Gift Program, the “Impact – Murphy Makes a Difference” Program, or on their own with a Company match for donations.
We also believe that the well-being of our employees is enhanced when they can give back to their local 12 Table of Contents PART I Item 1. Business - Continued communities or charities through programs like the Company Matching Gift Program, the “Impact – Murphy Makes a Difference” Program, or on their own with a Company match for donations.
The most common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH), Heavy Louisiana Sweet (HLS) and Brent. The average New York Mercantile Exchange (NYMEX) natural gas sales price was $2.24 per million British Thermal Units (MMBTU) in 2024, compared to $2.53 in 2023 and $6.38 in 2022.
The most common crude oil indices used to price the Company’s crude include Mars, WTI Houston Magellan East Houston, Heavy Louisiana Sweet and Brent. The average New York Mercantile Exchange (NYMEX) natural gas sales price was $3.54 per million British Thermal Units (MMBTU) in 2025, compared to $2.24 in 2024 and $2.53 in 2023.
The goals of the MPM process are the following: • Drive behavior to align with the Company’s mission, vision, values and behaviors; • Develop employee capabilities through effective feedback and coaching; and • Maintain a process that is consistent throughout the organization to measure employee performance that is tied to the Company’s and stockholders’ interests. 11 Table of Contents PART I Item 1.
The goals of the MPM process are the following: • Drive performance that aligns with the Company’s mission, vision, values and behaviors; • Develop employee capabilities through effective feedback and coaching; and • Maintain a process that is consistent throughout the organization to measure employee performance that is tied to the Company’s and stockholders’ interests.
The Company also has exposure to the Canadian benchmark natural gas price, Alberta Energy Company (AECO), which averaged C$1.46 per MCF in 2024, compared to C$2.64 in 2023 and C$5.31 in 2022.
The Company also has exposure to the Canadian benchmark natural gas price, Alberta Energy Company (AECO), which averaged C$1.68 per thousand cubic feet (MCF) in 2025, compared to C$1.46 in 2024 and C$2.64 in 2023.
In January 2025, however, President Trump signed a series of executive orders that call upon the EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, direct federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, transportation, and refining, and mandate a review of existing regulations that may burden domestic energy development.
In January 2025, however, President Trump signed a series of executive orders that call upon the EPA to reassess the endangerment finding for GHGs under the Clean Air Act, direct federal executive departments and agencies to freeze rules that have not taken effect, to identify and exercise emergency authorities to facilitate conventional energy production, transportation, and refining, and mandate a review of existing regulations that may burden domestic energy development.
We strive to empower our leadership with programs that offer career advancement for experienced and emerging leaders. In 2024, over 50 managers participated in a leadership program, from a top-rated institution, addressing focus areas such as strategic agility, decision making, building high-performing teams and enhancing trust.
We strive to empower our leadership with programs that offer career advancement for experienced and emerging leaders. In 2025, approximately 135 leaders participated in programs, from top-rated institutions, addressing focus areas such as strategic agility, decision making, building high-performing teams and enhancing trust.
In Canada, the Company is subject to Federal Occupational Health and Safety Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia) and the Workplace Hazardous Materials Information System. 10 Table of Contents PART I Item 1.
In Canada, the Company is subject to Federal Occupational Health and Safety Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia) and the Workplace Hazardous Materials Information System.
Murphy’s ability to operate profitably in the exploration and production 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. Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.
Risk Factors - Continued 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. Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.
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 15 Table of Contents PART I Item 1A.
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.
The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2024, and including noncontrolling interests, approximately 33% of the Company’s crude oil proved reserves, 38% of NGL proved reserves and 45% of natural gas proved reserves are undeveloped.
The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2025, and including noncontrolling interests, approximately 36% of the Company’s crude oil proved reserves, 41% of NGL proved reserves and 47% of natural gas proved reserves are undeveloped.
Risk Factors - Continued • natural disasters such as hurricanes and tornadoes, including those that may result from climate change; • the price, availability and the demand for and of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar; • the effect of conservation efforts and focus on climate-change; • technological advances affecting energy consumption and energy supply; • increased activism against, or change in public sentiment for, oil and natural gas exploration, development, and production activities and considerations including climate change and the transition to a lower carbon economy; • the occurrence or threat of epidemics or pandemics, such as the outbreak of COVID-19, or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels; • domestic and foreign governmental regulations, taxes and other actions, including tariffs, economic sanctions and further legislation requiring, subsidizing or providing tax benefits for the use or generation of alternative energy sources and fuels; and • general economic conditions worldwide, including inflationary conditions and related governmental policies and interventions.
Risk Factors - Continued • the production levels of non-OPEC countries, including, among others, production levels in the North American shale plays; • political instability or armed conflict in oil and natural gas producing regions, such as the Russia-Ukraine and Israeli-Palestinian conflicts and political instability in Venezuela and Iran; • the level of drilling, completion and production activities by other E&P companies, and variability therein, in response to market conditions; • changes in weather patterns and climate, including those that may result from climate change; • natural disasters such as hurricanes and tornadoes, including those that may result from climate change; • the price, availability and the demand for and of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar; • the effect of conservation efforts and focus on climate-change; • technological advances, such as artificial intelligence (AI) and data center development, affecting energy consumption and energy supply; • increased activism against, or change in public sentiment for, oil and natural gas exploration, development, and production activities and considerations including climate change and the transition to a lower carbon economy; • the occurrence or threat of epidemics or pandemics, such as the outbreak of COVID-19, or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels; • domestic and foreign governmental regulations, taxes and other actions, including tariffs, economic sanctions and further legislation requiring, subsidizing or providing tax benefits for the use or generation of alternative energy sources and fuels; and • general economic conditions worldwide, including inflationary conditions and related governmental policies and interventions.
These reserve reductions could be significant. • Lower oil and natural gas prices could lead to an inability to access, renew, or replace credit facilities, and could also impair access to other sources of funding as these mature, potentially negatively impacting our liquidity. 14 Table of Contents PART I Item 1A.
These reserve reductions could be significant. • Lower oil and natural gas prices could lead to an inability to access, renew, or replace credit facilities, and could also impair access to other sources of funding as these mature, potentially negatively impacting our liquidity. • Lower prices for oil and natural gas could cause the Company to lower its dividend because of lower cash flows.
Lower oil and natural gas prices adversely affect the Company in several ways: • Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income. • Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves. • Lower oil and natural gas prices could lead to impairment charges in future periods, therefore reducing net income. • Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years.
Lower oil and natural gas prices adversely affect the Company in several ways: • Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income. • Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves. 14 Table of Contents PART I Item 1A.
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, 16 Table of Contents PART I Item 1A.
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.
Risk Factors - Continued including, but not limited to, commodity prices, fiscal regime changes, government project approval delays, regulatory changes, credit downgrades and regional conflict.
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.
A “development” well is drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
A “development” well is drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. The following table shows the number of oil and natural gas wells producing or capable of producing at December 31, 2025.
Exploration Development Total Gross Net Gross Net Gross Net United States Onshore — — 22.0 11.2 22.0 11.2 Offshore — — 1.0 0.3 1.0 0.3 Canada Onshore — — 5.0 5.0 5.0 5.0 Offshore — — — — — — Other — — 1.0 0.4 1.0 0.4 Totals — — 29.0 16.9 29.0 16.9 8 Table of Contents PART I Item 1.
Exploration Development Total Gross Net Gross Net Gross Net United States Onshore — — 25.0 18.3 25.0 18.3 Offshore 2.0 1.0 1.0 0.1 3.0 1.1 Canada Onshore — — 4.0 2.8 4.0 2.8 Offshore — — 1.0 0.1 1.0 0.1 Other 1.0 0.4 1.0 0.4 2.0 0.8 Totals 3.0 1.4 32.0 21.7 35.0 23.1 8 Table of Contents PART I Item 1.
In 2024, 71.6% of the proved reserves were audited by third-party auditors.
In 2025, 95.8% of the proved reserves were audited by third-party auditors.
In furtherance of that commitment, Murphy, through its policies and its actions, requires strict compliance with all anti-harassment and anti-discrimination laws and does not tolerate harassment or discrimination of any kind based on any protected characteristic. 12 Table of Contents PART I Item 1.
In furtherance of that commitment, Murphy, through its policies and its actions, requires strict compliance with all anti-harassment and anti-discrimination laws and does not tolerate harassment or discrimination of any kind based on any protected characteristic. Finally, we support interest-based groups such as sports and charity volunteering in our communities.
The information contained on the Company’s Website is not part of, or incorporated into, this report on Form 10-K.
Website Access to SEC Reports Murphy Oil’s internet address is http://www.murphyoilcorp.com. The information contained on the Company’s Website is not part of, or incorporated into, this report on Form 10-K.
Certain of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its revenue generating properties.
Risk Factors - Continued Murphy is sometimes reliant on joint venture partners for operating assets, and/or funding development projects and operations. Certain of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its revenue generating properties.
Operational Risk Factors Murphy operates in highly competitive environments which could adversely affect it in many ways, including its profitability, cash flows and its ability to grow.
See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices. Operational Risk Factors Murphy operates in highly competitive environments which could adversely affect it in many ways, including its profitability, cash flows and its ability to grow.
If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business. 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.
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.
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 will 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, 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 may not fully benefit from the price improvement on all production.
Our inability to access appropriate equipment and infrastructure in a timely manner and on acceptable terms may hinder our access to oil and natural gas markets or delay our oil and natural gas production. Murphy is sometimes reliant on joint venture partners for operating assets, and/or funding development projects and operations.
Our inability to access appropriate equipment and infrastructure in a timely manner and on acceptable terms may hinder our access to oil and natural gas markets or delay our oil and natural gas production. 16 Table of Contents PART I Item 1A.
To enhance employee understanding of their total remuneration package extended by Murphy, we introduced Total Reward Statements for employees in the U.S., Canada and Vietnam. For further details on the Company’s compensation framework, please see the Compensation Discussion and Analysis section of the forthcoming Proxy Statement relating to the Annual Meeting of Stockholders on May 14, 2025.
For further details on the Company’s compensation framework, please see the Compensation Discussion and Analysis section of the forthcoming Proxy Statement relating to the Annual Meeting of Stockholders on May 13, 2026.
Furthermore, we implemented a refreshed and expanded Technical Career Map to enhance the development of 125 engineering and geoscience employees. We encourage employee engagement and solicit feedback through internal surveys, focus groups and our employee-led Ambassador program to gain insights into workplace experiences.
Furthermore, we implemented a Business Functions Career Map to enhance the development of about 100 business professionals in our Controllers, Global Planning and Performance, Tax, Treasury and related functions. We encourage employee engagement and solicit feedback through internal surveys, focus groups and town hall meetings to gain insight into workplace experiences.
The Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well, located in offshore Vietnam, and the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well, located in the Gulf of America, resulted in commercial discoveries while the Sebastian #1 (Mississippi Canyon 387) and non-operated Orange #1 (Mississippi Canyon 216) wells, located in the Gulf of America, did not encounter commercial hydrocarbons.
The Lac Da Hong-1X (Pink Camel), Block 15-1/05 and the Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17 exploration wells, in Vietnam, resulted in commercial discoveries, while the Civette-1X (Block CI-502) exploration well, in Côte d’Ivoire, did not encounter commercial hydrocarbons.
Risk Factors - Continued • Lower prices for oil and natural gas could cause the Company to lower its dividend because of lower cash flows. See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices.
See Note K for additional information on the derivative instruments used to manage certain risks related to commodity prices. Murphy’s commodity price risk management may limit the Company’s ability to fully benefit from potential future price increases for oil and natural gas.
These factors include: • worldwide and domestic supplies of, and demand for, crude oil, natural gas and NGLs; • the ability of the members of the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC members, for example, Russia, to agree to maintain or adjust production levels; • the production levels of non-OPEC countries, including, amongst others, production levels in the 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 conflict; • the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions; • changes in weather patterns and climate, including those that may result from climate change; 13 Table of Contents PART I Item 1A.
These factors include: • worldwide and domestic supplies of, and demand for oil and natural gas; • the ability of the members of the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC members, for example, Russia, to agree to maintain or adjust production levels; 13 Table of Contents PART I Item 1A.
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.
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 E&P business, therefore, is dependent 15 Table of Contents PART I Item 1A.
Lower prices, should they occur, will materially and adversely affect our results of operations, cash flows and financial condition.
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.
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 million for its 2025 exploration program, which includes drilling two wells in Vietnam, two wells in the Gulf of America, and one well in Côte d’Ivoire.
Subsequent to year end, the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells, in the Gulf of America, resulted in commercial discoveries. The Company’s 2026 exploration and appraisal program capital expenditures guidance of $320 million includes drilling three wells in Vietnam and two wells in Côte d’Ivoire.
Removed
The methane WEC’s relationship to the IRA also means that the methane WEC’s implementation may be subject to further acts of the U.S. Congress. Thus, the future of the new methane and waste emission charge rules, as well as the regulation of GHGs by the U.S. federal government, may be subject to change in the near-term. Endangered and threatened species.
Added
Oil Wells Natural Gas Wells Gross Net Gross Net United States Onshore 1,251 1,008 30 5 Offshore 83 37 12 5 Total United States 1,334 1,045 42 10 Canada Onshore 18 13 369 352 Offshore 50 5 — — Total Canada 68 18 369 352 Totals 1,402 1,063 411 362 Murphy’s net wells drilled and completed in the last three years are shown in the following table.
Removed
Business - Continued The Board receives updates on employee composition and recruiting, hiring, promotion, and retention of employees from the Vice President, Human Resources and Administration on a regular cadence.
Added
As part of this shift, the Administration moved to halt the implementation of the WEC citing concerns about statutory authority, economic impacts on domestic energy production, and the need for further evaluation of methane measurement methodologies. This action resulted in the EPA withdrawal of WEC's supporting guidance, paused enforcement preparations, and announced its intent to reconsider the rule.
Removed
As of December 31, 2024, our U.S. and international workforce was comprised of approximately 24% females, and our U.S. workforce was comprised of approximately 33% of minority groups (as defined by the U.S. Equal Employment Opportunity Commission). We also support interest-based groups such as sports, hobbies, and charity volunteering in our communities.
Added
In May 2025, the agency issued a final rule formally removing the WEC from the Code of Federal Regulations. The One Big Beautiful Bill Act (OBBBA) passed in July 2025 postponed the implementation of the WEC to 2034. In September 2025, the EPA proposed a rollback of the Greenhouse Gas Reporting Program (GHGRP).
Removed
In 2024, we increased the number of employee-led, self-directed Employee Resource Groups with the introduction of ASPIRE (Asian and Pacific Islander Women) and VIPER (Veteran Integration and Purpose). Participation is voluntary, with membership and programming open to all Murphy employees. Website Access to SEC Reports Murphy Oil’s internet address is http://www.murphyoilcorp.com.
Added
The proposal would eliminate reporting requirements for most source categories after reporting year 2024 and postpone Subpart W reporting for petroleum and natural gas systems until 2034. If finalized, this would significantly reduce federal GHG data collection and delay methane reporting for nearly a decade.
Removed
Murphy’s commodity price risk management may limit the Company’s ability to fully benefit from potential future price increases for oil and natural gas. The Company, from time to time, enters into various contracts to protect its cash flows against lower oil and natural gas prices.
Added
Together, the repeal of the WEC regulations, the postponement of the WEC to 2034 and the proposed rollback of the GHGRP create substantial uncertainty for the future of overall federal methane regulation. The future of both will depend on the EPA’s rulemaking process, potential litigation, and possible congressional involvement. Endangered and threatened species. The U.S.
Removed
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.
Added
Further, on February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution.
Removed
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.
Added
The repeal calls into question EPA’s authority to regulate GHGs, as well as EPA’s prior scientific assessment of climate change risks. Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact EPA’s regulation of GHG emissions going forward. 10 Table of Contents PART I Item 1.
Removed
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 17 Table of Contents PART I Item 1A.
Added
To 11 Table of Contents PART I Item 1. Business - Continued enhance employee understanding of their total remuneration package extended by Murphy, we introduced Total Reward Statements for employees in the U.S., Canada and Vietnam.
Removed
Risk Factors - Continued 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.
Added
Risk Factors - Continued • Lower oil and natural gas prices could lead to impairment charges in future periods, therefore reducing net income. • Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years.
Removed
Murphy is subject to numerous environmental, health and safety laws and regulations, and such existing and any potential future laws and regulations may result in material liabilities and costs.
Added
One of these exploration wells in Côte d’Ivoire, Caracal-1X (Block CI-102), was completed in February 2026, and will be plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

20 edited+115 added−3 removed17 unchanged
Biggest changeAs part of Murphy’s strategy review process, the Company reviews hydrocarbon demand forecasts and assesses the impact on its business model, plans and future estimates of reserves. In addition, the Company evaluates other lower-carbon technologies that could complement our existing assets, strategy and competencies as part of its long-term capital allocation strategy.
Biggest changeFurther, a reduction in demand for fossil fuels could adversely impact the availability of future financing. As part of Murphy’s strategy review process, the Company reviews hydrocarbon demand forecasts and assesses the impact on its business model, plans and future estimates of reserves.
In addition, presidential administrations could issue various executive orders that may result in additional laws, rules and regulations in the area of climate change.
In addition, future presidential administrations could issue various executive orders that may result in additional laws, rules and regulations in the area of climate change.
Risk Factors - Continued A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of GHGs such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.
A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of GHGs such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.
While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the exploration and production business.
While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the E&P business.
The Company or certain of its consolidated subsidiaries are involved in numerous legal proceedings, including lawsuits for alleged personal injuries, environmental and/or property damages, climate change and other business-related matters. Certain of these claims may take many years to resolve through court and arbitration proceedings or negotiated settlements.
Lawsuits against Murphy and its subsidiaries could adversely affect its operating results. The Company or certain of its consolidated subsidiaries are involved in numerous legal proceedings, including lawsuits for alleged personal injuries, environmental and/or property damages, climate change and other business-related matters. Certain of these claims may take many years to resolve through court and arbitration proceedings or negotiated settlements.
The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future. Murphy could face long-term challenges to the fossil fuels business model reducing demand and price for hydrocarbon fuels.
The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future. Murphy could face long-term challenges to the fossil fuels business model reducing demand and price for hydrocarbon fuels. 25 Table of Contents PART I Item 1A.
International agreements such as the Paris Agreement and subsequent yearly “conferences of the parties” have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs, in addition to calls for transitioning away from fossil fuels and a pledge to achieve near-zero methane emissions by a specified future date.
International agreements have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs, in addition to calls for transitioning away from fossil fuels and a pledge to achieve near-zero methane emissions by a specified future date.
Administration’s approach to oil and natural gas leasing and permitting. In March 2024, the SEC adopted rules requiring disclosure of a wide range of climate change-related information, including, among other things, companies’ climate change risk management; short-, medium-, and long-term climate-related financial risks; and disclosure of Scope 1 and Scope 2 emissions.
In March 2024, the SEC adopted rules requiring disclosure of a wide range of climate change-related information, including, among other things, companies’ climate change risk management; short-, medium-, and long-term climate-related financial risks; and disclosure of Scope 1 and Scope 2 emissions.
Murphy’s business model may come under more pressure from changing environmental and social trends and the related global demands for non-fossil fuel energy sources. This demand in alternative forms of energy may cause the price of our products to become more volatile and decline. Further, a reduction in demand for fossil fuels could adversely impact the availability of future financing.
Risk Factors - Continued Murphy’s business model may come under more pressure from changing environmental and social trends and the related global demands for non-fossil fuel energy sources. This demand in alternative forms of energy may cause the price of our products to become more volatile and decline.
We cannot predict what changes to trade policy will be made by the Trump Administration, the U.S. Congress or other governments, including whether existing 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.
We cannot predict future changes to trade policy, including whether existing or future tariff policies will be maintained or modified or whether the entry into new trade agreements will occur, nor can we predict the effects that any such changes would have on our business.
Similar laws and regulations regarding climate change-related disclosures have been proposed or enacted in other jurisdictions, including California and the European Union. The SEC’s climate disclosure rules have been stayed pending legal challenges, but implementation of the rules as finalized could be costly and time consuming. On February 11, 2025, the SEC notified the U.S.
Similar laws and regulations regarding climate change-related disclosures have been proposed or enacted in other jurisdictions, including California and the European Union. The SEC’s climate disclosure rules have been stayed pending legal challenges and further action by the SEC, but implementation of the rules as finalized could be costly and time consuming. 24 Table of Contents PART I Item 1A.
As of December 31, 2024, 1.7% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada. 24 Table of Contents PART I Item 1A.
As of December 31, 2025, 1.8% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada.
With or without renewable-energy subsidies, the unknown pace and strength of technological advancement of non-fossil-fuel energy sources creates uncertainty about the timing and pace of effects on our business model.
With or without renewable-energy subsidies, the unknown pace and strength of technological advancement and adoption of non-fossil-fuel energy sources creates uncertainty about the timing and pace of effects on our business model. The Company continually monitors global climate change initiatives and plans accordingly based on its assessment of the effects of such initiatives on its business.
Such changes in trade policy or in laws and policies governing foreign trade, and any resulting negative sentiments as a result of such changes, could materially and adversely affect our business, financial condition, results of operations and liquidity.
These changes, and any resulting negative sentiments or retaliatory trade practices, could materially and adversely affect our business, financial condition, results of operations and liquidity.
Item 1A. Risk Factors - Continued Murphy is exposed to regulation, legislation and policies enacted by policy makers, regulators or other parties to delay or deny necessary licenses and permits to produce or transport crude oil and natural gas.
Murphy is exposed to regulation, legislation and policies enacted by policy makers, regulators or other parties to delay or deny necessary licenses and permits to produce or transport crude oil and natural gas. As an example, the Biden Administration pursued initiatives related to environmental, health and safety standards applicable to the oil and natural gas industry.
However, on December 14, 2023, the Secretary of the Interior approved the 2024-2029 National Outer Continental Shelf Oil and Gas Leasing Program, which contemplates only three potential oil and natural gas lease sales in the Gulf of America through 2029. These developments demonstrate the uncertainty that can arise from the U.S.
However, on December 14, 2023, the Secretary of the Interior approved the 2024-2029 National Outer Continental Shelf Oil and Gas Leasing Program, which contemplates only three potential oil and natural gas lease sales in the Gulf of America through 2029. These Biden Administration policies have largely been overturned by President Trump’s 2025 executive orders promoting American energy dominance.
The Company also has significant natural gas reserves which emit lower carbon compared to crude oil and NGLs. The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global GHG emissions.
The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global GHG emissions.
Court of Appeals not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the cases. These actions and any future changes to applicable environmental, health and safety, regulatory and legal requirements promulgated by the U.S.
Risk Factors - Continued These actions and any future changes to applicable environmental, health and safety, regulatory and legal requirements promulgated by the U.S.
For example, the Trump Administration has proposed additional tariffs on Canada and Mexico. Such tariffs may put upwards pressure on the prices of goods and services across the jurisdictions in which we operate, which could reduce our ability to offer competitive pricing to potential customers.
Such tariffs may put upwards pressure on the prices of goods and services across the jurisdictions in which we operate. In addition, the scope and durability of existing and future tariff measures remain uncertain.
UNRESOLVED STAFF COMMENTS The Company had no unresolved comments from the staff of the SEC as of December 31, 2024.
UNRESOLVED STAFF COMMENTS The Company had no unresolved comments from the staff of the SEC as of December 31, 2025. Item 1C. CYBERSECURITY Murphy’s cybersecurity environment and risk strategy is broadly managed by the Company’s IT group, which oversees the Company’s IT and OT infrastructure.
Removed
As an example, the Biden Administration pursued initiatives related to environmental, health and safety standards applicable to the oil and natural gas industry.
Added
Item 1A. Risk Factors - Continued 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.
Removed
Court of Appeals of a statement issued by the SEC’s Acting Chairman regarding, among other things, the fact that the majority of current SEC Commissioners had previously voted against adopting the rules, and requested that the U.S.
Added
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.
Removed
The Company continually monitors global climate change initiatives and plans accordingly based on its assessment of the effects of such initiatives on its business. 25 Table of Contents PART I Item 1A. Risk Factors - Continued Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.
Added
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.
Added
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.
Added
Murphy is subject to numerous environmental, health and safety laws and regulations, and such existing and any potential future laws and regulations may result in material liabilities and costs.
Added
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.
Added
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.
Added
For example, in March 2024, the EPA published New Source Performance 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 EPA.
Added
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 EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector.
Added
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.
Added
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.
Added
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.
Added
Murphy also could be subject to strict liability for environmental contamination in various jurisdictions where it operates, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors.
Added
Contamination has been identified at some locations, and the Company has been required, and in the future may be required, to investigate, remove or remediate previously disposed wastes; or otherwise clean up contaminated soil, surface water or groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations.
Added
In addition to significant investigation and remediation costs, such matters can result in fines and also give rise to third-party claims for personal injury and property or other environmental damage. 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.
Added
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 18 Table of Contents PART I Item 1A.
Added
Risk Factors - Continued British Columbia and Alberta also govern various aspects of hydraulic fracturing activities under their jurisdictions.
Added
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.
Added
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 increase. Once new laws and/or regulations have been enacted and adopted, the costs of compliance are appraised.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
These developments demonstrate the uncertainty regarding the regulation of oil and natural gas related to shifts in political power in the U.S.
Added
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.” We face various risks associated with increased activism against, or change in public sentiment for, oil and natural gas exploration, development, and production activities and sustainability considerations, including climate change and the transition to a lower carbon economy.
Added
Opposition toward oil and natural gas drilling, development, and production activity has grown 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.
Added
Anti‑development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development, onshore hydraulic fracking, and construction of pipelines for oil and natural gas. Activism may continue to increase regardless of the U.S. Administration’s environmental and climate change executive orders described earlier in this Form 10-K report.
Added
Our need to incur costs associated with responding to these initiatives or complying with any new legal requirements resulting from these activities that are substantial and not adequately provided for could have a material adverse effect on our business, financial condition and results of operations.
Added
In addition, a change in public sentiment regarding the oil and natural gas industry could result in a reduction in the demand for our products or otherwise affect our results of operations or financial condition.
Added
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.
Added
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.
Added
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.
Added
In recent years, certain stakeholders and regulators have also proposed “anti-ESG” policies, legislation or initiatives. This 19 Table of Contents PART I Item 1A. Risk Factors - Continued divergence in stakeholder expectations could expose us to reputational risks and potentially disrupt relationships with certain stakeholders.
Added
While the Company has been named a co-defendant with other oil and natural gas companies in lawsuits related to climate change, these lawsuits have not resulted in, and are not currently expected to result in, material liability for the Company.
Added
Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.
Added
For further details on risks related to legal proceedings more generally, see “Risk Factors - General Risk Factors - Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.” Financial Risk Factors Capital financing may not always be available to fund Murphy’s activities; and interest rates could impact cash flows.
Added
Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production.
Added
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.
Added
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.
Added
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.
Added
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.
Added
The Company’s ability to obtain additional financing is affected by a number of factors, including the market environment, our operating and financial performance, investor sentiment, our ability to incur additional debt in compliance with agreements governing our outstanding debt, and the Company’s credit ratings.
Added
A ratings downgrade could materially and adversely impact the Company’s ability to access debt markets, increase the borrowing cost under the Company’s credit facility and the cost of any additional indebtedness we incur, and potentially require the Company to post additional letters of credit or other forms of collateral for certain obligations.
Added
Murphy partially manages this risk through borrowing at fixed rates wherever possible; however, rates when refinancing or raising new capital are determined by factors outside of the Company’s control. Further, changes in investors’ sentiment or view of risk of the E&P industry, including as a result of concerns over climate change, could adversely impact the availability of future financing.
Added
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.
Added
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. Since 2022, the Company undertook several actions to reduce overall debt.
Added
Murphy plans to continue with the Company’s deleveraging initiatives, but there can be no assurance that these efforts will be successful and, if not, the Company’s financial conditions and prospects could be adversely affected. See Note F for information regarding the Company’s outstanding debt as of December 31, 2025.
Added
We may be unable to meet our capital allocation plan 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.
Added
Our capital allocation plan includes returning a percentage of adjusted FCF 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.
Added
There can be no assurance 20 Table of Contents PART I Item 1A. Risk Factors - Continued 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.
Added
In connection with our capital allocation 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.
Added
We can provide no assurance that we will make share repurchases or pay dividends in accordance with our capital allocation plan, or at all. Any elimination of, or downward revision in, our share repurchase program, dividend payment plans, or capital allocation plan could have an adverse effect on the market price of our common stock.
Added
Meeting our capital allocation plan strategy requires us to generate consistent adjusted FCF 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.
Added
The amount of adjusted FCF returned in any quarter during the year may vary and may be more or less than our capital allocation plan.
Added
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. Murphy’s operations could be adversely affected by changes in foreign exchange rates.
Added
The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, and therefore the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

3 edited+0 added−5 removed4 unchanged
Biggest changeThe Audit Committee is ultimately responsible for overseeing cybersecurity strategy and ensuring that management has sufficient resources, programs, and processes in place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents.
Biggest changeItem 1C. Cybersecurity - Continued place to identify, evaluate, manage, and mitigate relevant cybersecurity risks to which Murphy is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the Board as appropriate.
To our knowledge, Murphy has not experienced any cybersecurity incidents that have had, or are likely to have, material impacts to our business, operations, finances, or reputation. 26 Table of Contents PART I
To our knowledge, Murphy has not experienced any cybersecurity incidents that have had, or are likely to have, material impacts to our business, operations, finances, or reputation. 27 Table of Contents PART I
The Audit Committee also reports material cybersecurity risks to the Board as appropriate. We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected.
We believe this visibility and oversight structure allows the Board and executive leadership team to make timely, data-driven decisions ensuring that Murphy, its employees, investors, and partners are adequately protected. Murphy considers its cybersecurity risk management framework to be a core component of its overall enterprise risk management system.
Removed
Item 1C. CYBERSECURITY Murphy’s cybersecurity environment and risk strategy is broadly managed by the Company’s Information Technology (IT) group, which oversees the Company’s IT and Operational Technology (OT) infrastructure.
Removed
Within the IT group, the Murphy Cybersecurity Team (MCT) is specifically responsible for monitoring and managing security of the enterprise IT and OT network and systems, including developing and deploying administrative policies, technical controls, and safety protocols necessary to prevent unauthorized access, theft, damage, or loss of Company data or systems.
Removed
All members of the MCT hold globally-recognized security certifications and have wide-ranging experience in cybersecurity matters. The Incident Management Team (IMT) is responsible for responding to active security threats and incidents as they occur.
Removed
The Chief Information Officer oversees the IT group and is a member of the IMT, and provides briefings to the CEO, the executive leadership team, and the Audit Committee of the Board regarding cybersecurity risks, strategy, and management at least annually.
Removed
Murphy considers its cybersecurity risk management framework to be a core component of its overall enterprise risk management system.

Item 2. Properties

Properties — owned and leased real estate

1 edited+0 added−0 removed1 unchanged
Biggest changeInformation required by the Securities Exchange Act Industry Guide No. 2 can be found in the “ Supplemental Oil and Natural Gas Information ” section of this Annual Report on Form 10-K on pages 106 to 121 and in Note D beginning on page 77 .
Biggest changeInformation required by the Securities Exchange Act Industry Guide No. 2 can be found in the “ Supplemental Oil and Natural Gas Information ” section of this Annual Report on Form 10-K on pages 111 to 126 and in Note D beginning on page 79 .

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

12 edited+2 added−3 removed0 unchanged
Biggest changeJumawan - Age 48; Vice President, Corporate Planning and Treasurer since 2022. Mr. Jumawan was Assistant Treasurer from 2017 to 2022. Maria A. Martinez – Age 50; Vice President, Human Resources and Administration since 2018. Ms. Martinez was Vice President, Human Resources of Murphy Exploration & Production Company from 2013 to 2018.
Biggest changeMartinez – Age 51; Senior Vice President, Human Resources, Administration and Communications since August 2025. Ms. Martinez was Vice President, Human Resources and Administration from 2018 to August 2025. Atif Riaz - Age 38; Vice President, Investor Relations & Treasurer since November 2025. Mr. Riaz was Vice President & Treasurer from August 2025 to October 2025.
This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors. During the three months ended December 31, 2024, the Company did not repurchase any shares of its common stock.
This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors. During the three months ended December 31, 2025, the Company did not repurchase any shares of its common stock.
Executive officers are elected annually but may be removed from office at any time by the Board. Eric M. Hambly – Age 50; President and Chief Executive Officer since January 2025. Mr. Hambly served as President and Chief Operating Officer from February 2024 to December 2024. Mr.
Executive officers are elected annually but may be removed from office at any time by the Board. Eric M. Hambly – Age 51; President and Chief Executive Officer since January 2025. Mr. Hambly served as President and Chief Operating Officer from February 2024 to December 2024. Mr.
Hambly also served as Executive Vice President, Operations from 2020 to 2024 and Executive Vice President, Onshore from 2018 to 2020. Thomas J. Mireles – Age 52; Executive Vice President and Chief Financial Officer since 2022. Mr. Mireles was Senior Vice President, Technical Services from 2018 to 2022. Mr.
Hambly also served as Executive Vice President, Operations from 2020 to 2024 and Executive Vice President, Onshore from 2018 to 2020. Thomas J. Mireles – Age 53; Executive Vice President & Chief Financial Officer since 2022. Mr. Mireles was Senior Vice President, Technical Services from 2018 to 2022. Mr.
Mireles also served as the Senior Vice President, Eastern Hemisphere of Murphy Exploration & Production Company from 2016 to 2018. E. Ted Botner – Age 60; Executive Vice President, General Counsel and Corporate Secretary since February 2024. Mr. Botner served as Senior Vice President, General Counsel and Corporate Secretary from 2020 to 2024.
Mireles also served as the Senior Vice President, Eastern Hemisphere of Murphy Exploration & Production Company from 2016 to 2018. E. Ted Botner – Age 61; Executive Vice President, General Counsel & Corporate Secretary since February 2024. Mr. Botner served as Senior Vice President, General Counsel & Corporate Secretary from 2020 to 2024.
Information on dividends per share by quarter for 2024 and 2023 are reported on page 122 of this Form 10-K report. 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.
Information on dividends per share by quarter for 2025 and 2024 are reported on page 127 of this Form 10-K report. 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.
Item 4. MINE SAFETY DISCLOSURES Not applicable. 27 Table of Contents PART I Information about our Executive Officers The present corporate office, length of service in office, and age at February 1, 2025, for each of the Company’s executive officers are reported in the following listing.
Item 4. MINE SAFETY DISCLOSURES Not applicable. 28 Table of Contents PART I Information about our Executive Officers The present corporate office, length of service in office, and age at February 1, 2026, for each of the Company’s executive officers are reported in the following listing.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The Company’s common stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 1,873 stockholders of record as of December 31, 2024.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The Company’s common stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 1,808 stockholders of record as of January 31, 2026.
He also served as Vice President, Law and Corporate Secretary from 2015 to 2020 and Manager, Law and Corporate Secretary from 2013 to 2015. Daniel R. Hanchera - Age 67; Senior Vice President, Business Development since 2022. Mr. Hanchera served as Senior Vice President, Business Development of Murphy Exploration & Production Company from 2014 to 2022.
He also served as Vice President, Law & Corporate Secretary from 2015 to 2020. Daniel R. Hanchera - Age 68; Senior Vice President, Business Development since 2022. Mr. Hanchera served as Senior Vice President, Business Development of Murphy Exploration & Production Company from 2014 to 2022. Maria A.
Since the inception of the share repurchase program through the end of the fourth quarter of 2024, the Company has repurchased 11.4 million shares of its common stock in open-market transactions. As of December 31, 2024, the Company had $650.1 million of its common stock remaining available to repurchase under the program.
Since the inception of the share repurchase program through the end of the fourth quarter of 2025, the Company has repurchased 15.0 million shares of its common stock in open-market transactions. As of December 31, 2025, the Company had $550.1 million of its common stock remaining available to repurchase under the program. 30 Table of Contents PART II
Vaughan – Age 58, Vice President and Controller since 2022. Mr. Vaughan was Vice President and Controller, U.S., Central and South America of Murphy Exploration & Production Company from 2017 to 2022. Kelly L. Whitley – Age 59; Vice President, Investor Relations and Communications since 2015. 28 Table of Contents PART II Item 5.
Vaughan was Vice President & Controller, U.S., Central and South America of Murphy Exploration & Production Company from 2017 to 2022. 29 Table of Contents PART II Item 5.
Issuer Purchases of Equity Securities The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock. Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws.
Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws.
Removed
He also served as Vice President, Business Development and Planning of Murphy Exploration & Production Company from 2009 to 2014. John B. Gardner – Age 56; Vice President, Marketing and Supply Chain since 2022. Mr. Gardner was Vice President and Treasurer from 2015 to 2022 and served as Treasurer from 2013 to 2015. Leyster L.
Added
He also served as Chief Information & Digital Officer from October 2021 to August 2025 and as General Manager, Process Transformation from 2019 to 2021. Paul D. Vaughan – Age 59; Vice President & Controller since 2022. Mr.
Removed
Meenambigai Palanivelu - Age 51; Vice President, Sustainability since 2023. Ms. Palanivelu was Director, Sustainability from 2020 to 2023. Ms. Palanivelu also served as the General Manager, Planning and Performance from 2019 to 2020 and General Manager, Finance Operating Model Program Management Office from 2017 to 2019. Louis W. Utsch – Age 59; Vice President, Tax since 2018. Paul D.
Added
Information concerning securities authorized for issuance under equity compensation plans will be disclosed in our definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026. Issuer Purchases of Equity Securities The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock.
Removed
Subsequent to year end, as of February 25, 2025, the Company repurchased 3.4 million shares of its common stock in open-market transactions for $95.1 million, excluding taxes and fees. As of this date, the Company had $555.0 million of its common stock remaining available to repurchase under the program. 29 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

25 edited+10 added−6 removed3 unchanged
Biggest changeSignificant Company financial and operational highlights during 2024 were as follows: • Generated net income of $486.5 million ($407.2 million excluding NCI and net cash provided by operating activities of $1,729.0 million; • Produced 184 thousand BOEPD (177 thousand BOEPD excluding NCI); • Issued $600.0 million of 6.000% senior notes due 2032, and used proceeds to redeem an aggregate $600.0 million of senior notes due 2027, 2028 and 2029; • Entered into a new five-year, $1.35 billion senior unsecured credit facility, representing a 69% increase from previous facility size; • Advances made under the capital allocation framework 1 : ◦ Repurchased $50.0 million of long-term debt; ◦ Repurchased 8.0 million shares of common stock under the share repurchase program for $300.0 million ($302.7 million including excise taxes and fees); • Achieved 84% (83% excluding NCI) total proved reserve replacement with year-end proved reserves of 729.0 million MMBOE (713.1 MMBOE excluding NCI); • Drilled an oil discovery at Hai Su Vang-1X (Golden Sea Lion) in offshore Vietnam and encountered approximately 370 feet of net oil pay from two reservoirs; and • Drilled a discovery at the non-operated Ocotillo #1 exploration well in Mississippi Canyon 40 in the Gulf of America and found 100 feet of net pay across two zones. 1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024.
Biggest changeSignificant Company financial and operational highlights during 2025 were as follows: • Generated net income of $138.8 million ($104.2 million excluding NCI) and net cash provided by operating activities of $1,247.8 million; • Produced 189 thousand BOEPD (182 thousand BOEPD excluding NCI); • Repurchased 3.6 million shares of common stock under the share repurchase program for $100.0 million ($100.8 million including excise taxes and fees) under the capital allocation plan 1 ; • Achieved 101% (103% excluding NCI) total proved reserve replacement with year-end proved reserves of 730.0 million MMBOE (715.0 MMBOE excluding NCI); • Closed the strategic acquisition of the Pioneer floating production, storage and offloading vessel (FPSO) in the Gulf of America for a gross purchase price of $125.0 million; and • Drilled oil discoveries at the Lac Da Hong-1X (Pink Camel), Block 15-1/05 and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells in Vietnam.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued SHAREHOLDER RETURN PERFORMANCE PRESENTATION The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2019 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued SHAREHOLDER RETURN PERFORMANCE PRESENTATION The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2020 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group.
Discussion and analysis of 2022 results and year-over-year comparisons between 2023 and 2022 are not included in this Form 10-K and can be found in “Item 7” of the 2023 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.
Discussion and analysis of 2023 results and year-over-year comparisons between 2024 and 2023 are not included in this Form 10-K and can be found in “Item 7” of the 2024 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Murphy’s continuing operations generate revenue by producing crude oil, natural gas and NGLs in the U.S. and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of crude oil, natural gas and NGLs.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Murphy’s continuing operations generate revenue by producing oil and natural gas in the U.S. and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of oil and natural gas.
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. 31 Table of Contents PART II Item 7.
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. 32 Table of Contents PART II Item 7.
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.
In order to make a profit and generate cash in its E&P business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Sales Volumes The following table contains hydrocarbons sold during the three years ended December 31, 2024. For further discussion on volumes, please see “ Revenues from Production ” section on page 37 .
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Sales Volumes The following table contains hydrocarbons sold during the three years ended December 31, 2025. For further discussion on volumes, please see “ Revenues from Production ” section on page 38 .
Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company with both onshore and offshore operations and properties. The Company produces crude oil, natural gas and NGLs primarily in the U.S. and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide.
Murphy Oil Corporation is a worldwide oil and natural gas E&P company with both onshore and offshore operations and properties. The Company produces oil and natural gas primarily in the U.S. and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide.
XOP Index reports a comprehensive view of the oil and natural gas exploration and production segment of the S&P Total Market Index, which is more comparable for the Company than the S&P 500 Index. Our peer group for 2024 is presented in the table below.
XOP Index reports a comprehensive view of the oil and natural gas E&P segment of the S&P Total Market Index, which is more comparable for the Company than the S&P 500 Index. Our peer group for 2025 is presented in the table below.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Results of Operations Murphy’s Net income (loss) by type of business and geographic segment is presented below: ( Millions of dollars ) 2024 2023 2022 Exploration and production United States $ 561.9 $ 905.1 $ 1,521.9 Canada 49.0 41.6 134.2 Other International (12.5) (65.5) (77.0) Total exploration and production 598.4 881.2 1,579.1 Corporate and other (109.1) (156.0) (438.3) Income from continuing operations 489.3 725.2 1,140.8 Loss from discontinued operations 1 (2.8) (1.5) (2.1) Net income including noncontrolling interest 486.5 723.7 1,138.7 Net income attributable to noncontrolling interest 79.3 62.1 173.7 Net income attributable to Murphy $ 407.2 $ 661.6 $ 965.0 1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Results of Operations Murphy’s Net income (loss) by type of business and geographic segment is presented below: ( Millions of dollars ) 2025 2024 2023 Exploration and production United States $ 308.5 $ 561.9 $ 905.1 Canada 54.8 49.0 41.6 Other International (66.6) (12.5) (65.5) Total exploration and production 296.7 598.4 881.2 Corporate and other (158.4) (109.1) (156.0) Income from continuing operations 138.3 489.3 725.2 Income (loss) from discontinued operations 1 0.5 (2.8) (1.5) Net income including noncontrolling interest 138.8 486.5 723.7 Net income attributable to noncontrolling interest 34.6 79.3 62.1 Net income attributable to Murphy $ 104.2 $ 407.2 $ 661.6 1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference. The companies in the peer group include: APA Corporation Kosmos Energy Ltd. Range Resources Corporation Civitas Resources Inc.
This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference. The companies in the peer group include: APA Corporation Expand Energy Corporation Permian Resources Corporation Chord Energy Corporation EOG Resources, Inc.
For the year ended December 31, 2024, the Company’s net income from continuing operations was $489.3 million, a decrease of $235.9 million compared to 2023.
For the year ended December 31, 2025, the Company’s net income from continuing operations was $138.3 million, a decrease of $351.0 million compared to 2024.
Pricing The following table contains the weighted average sales prices for the three years ended December 31, 2024: (Weighted average sales prices) 2024 2023 2022 Crude oil and condensate – dollars per barrel United States - Onshore $ 75.77 $ 76.96 $ 96.00 United States - Offshore 1 76.36 77.38 94.21 Canada - Onshore 2 67.49 72.84 89.88 Canada - Offshore 2 82.22 84.20 107.47 Other 2 77.59 86.60 94.37 Natural gas liquids – dollars per barrel United States - Onshore 20.20 19.69 33.85 United States - Offshore 1 23.37 21.94 36.01 Canada - Onshore 2 34.14 35.87 55.65 Natural gas – dollars per thousand cubic feet United States - Onshore 1.90 2.26 6.04 United States - Offshore 1 2.40 2.78 6.97 Canada - Onshore 2 1.59 2.06 2.76 1 Prices include the effect of noncontrolling interest in MP GOM. 2 U.S. dollar equivalent. 34 Table of Contents PART II Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Pricing The following table contains the weighted average sales prices for the three years ended December 31, 2025: 2025 2024 2023 Crude oil and condensate – dollars per barrel United States - Onshore $ 64.59 $ 75.77 $ 76.96 United States - Offshore 1 65.69 76.36 77.38 Canada - Onshore 2 57.16 67.49 72.84 Canada - Offshore 2 68.77 82.22 84.20 Other 2 69.26 77.59 86.60 Natural gas liquids – dollars per barrel United States - Onshore 19.38 20.20 19.69 United States - Offshore 1 20.40 23.37 21.94 Canada - Onshore 2 29.60 34.14 35.87 Natural gas – dollars per thousand cubic feet United States - Onshore 2.91 1.90 2.26 United States - Offshore 1 3.75 2.40 2.78 Canada - Onshore 2 1.79 1.59 2.06 1 Prices include the effect of the noncontrolling interest in MP GOM. 2 U.S. dollar equivalent.
(Barrels per day unless otherwise noted) 2024 2023 2022 Net crude oil and condensate United States - Onshore 21,151 24,070 24,437 United States - Offshore 1 63,047 73,473 65,411 Canada - Onshore 2,868 2,937 4,005 Canada - Offshore 7,251 3,020 2,812 Other 219 250 700 Total net crude oil and condensate 94,536 103,750 97,365 Net natural gas liquids United States - Onshore 4,442 4,617 5,181 United States - Offshore 1 4,544 5,924 4,597 Canada - Onshore 597 681 903 Total net natural gas liquids 9,583 11,222 10,681 Net natural gas – thousands of cubic feet per day United States - Onshore 25,028 25,863 29,050 United States - Offshore 1 57,228 70,239 63,380 Canada - Onshore 398,786 369,906 310,230 Total net natural gas 481,042 466,008 402,660 Total net hydrocarbons - including NCI 2,3 184,293 192,640 175,156 Noncontrolling interest Net crude oil and condensate – barrels per day (6,358) (6,210) (7,452) Net natural gas liquids – barrels per day (199) (220) (280) Net natural gas – thousands of cubic feet per day (1,942) (2,089) (2,468) Total noncontrolling interest 2,3 (6,881) (6,778) (8,143) Total net hydrocarbons - excluding NCI 2,3 177,412 185,862 167,013 Estimated total proved net hydrocarbon reserves - million equivalent barrels 3,4 729.0 739.5 715.4 1 Includes net volumes attributable to a noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 3 NCI – noncontrolling interest in MP GOM. 4 December 31, 2024, 2023 and 2022, include 15.9 MMBOE, 15.5 MMBOE and 18.2 MMBOE, respectively, relating to noncontrolling interest. 35 Table of Contents PART II Item 7.
(Barrels per day unless otherwise noted) 2025 2024 2023 Net crude oil and condensate United States - Onshore 26,186 21,151 24,070 United States - Offshore 1 56,797 63,047 73,473 Canada - Onshore 2,958 2,868 2,937 Canada - Offshore 6,981 7,251 3,020 Other 275 219 250 Total net crude oil and condensate 93,197 94,536 103,750 Net natural gas liquids United States - Onshore 5,870 4,442 4,617 United States - Offshore 1 4,436 4,544 5,924 Canada - Onshore 521 597 681 Total net natural gas liquids 10,827 9,583 11,222 Net natural gas – thousands of cubic feet per day United States - Onshore 33,415 25,028 25,863 United States - Offshore 1 51,793 57,228 70,239 Canada - Onshore 422,742 398,786 369,906 Total net natural gas 507,950 481,042 466,008 Total net hydrocarbons - including noncontrolling interest 2 188,682 184,293 192,640 Noncontrolling interest Net crude oil and condensate – barrels per day (5,876) (6,358) (6,210) Net natural gas liquids – barrels per day (217) (199) (220) Net natural gas – thousands of cubic feet per day (1,767) (1,942) (2,089) Total noncontrolling interest 2 (6,388) (6,881) (6,778) Total net hydrocarbons - excluding noncontrolling interest 2 182,294 177,412 185,862 Estimated total proved net hydrocarbon reserves - million equivalent barrels 3 730.0 729.0 739.5 1 Includes net volumes attributable to the noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 3 Proved reserves at December 31, 2025, 2024 and 2023, include 15.0 MMBOE, 15.9 MMBOE and 15.5 MMBOE, respectively, attributable to NCI. 36 Table of Contents PART II Item 7.
(Barrels per day unless otherwise noted) 2024 2023 2022 Net crude oil and condensate United States - Onshore 21,151 24,070 24,437 United States - Offshore 1 63,612 73,373 64,840 Canada - Onshore 2,868 2,937 4,005 Canada - Offshore 6,445 2,559 3,002 Other 230 349 663 Total net crude oil and condensate 94,306 103,288 96,947 Net natural gas liquids United States - Onshore 4,443 4,617 5,181 United States - Offshore 1 4,543 5,924 4,597 Canada - Onshore 597 681 903 Total net natural gas liquids 9,583 11,222 10,681 Net natural gas – thousands of cubic feet per day United States - Onshore 25,028 25,863 29,050 United States - Offshore 1 57,228 70,239 63,380 Canada - Onshore 398,786 369,906 310,230 Total net natural gas 481,042 466,008 402,660 Total net hydrocarbons - including NCI 2,3 184,063 192,178 174,738 Noncontrolling interest Net crude oil and condensate – barrels per day (6,438) (6,200) (7,369) Net natural gas liquids – barrels per day (198) (220) (280) Net natural gas – thousands of cubic feet per day (1,942) (2,089) (2,468) Total noncontrolling interest 2,3 (6,960) (6,768) (8,060) Total net hydrocarbons - excluding NCI 2,3 177,103 185,410 166,678 1 Includes net volumes attributable to a noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 3 NCI – noncontrolling interest in MP GOM. 36 Table of Contents PART II
(Barrels per day unless otherwise noted) 2025 2024 2023 Net crude oil and condensate United States - Onshore 26,186 21,151 24,070 United States - Offshore 1 56,532 63,612 73,373 Canada - Onshore 2,958 2,868 2,937 Canada - Offshore 7,451 6,445 2,559 Other 226 230 349 Total net crude oil and condensate 93,353 94,306 103,288 Net natural gas liquids United States - Onshore 5,870 4,443 4,617 United States - Offshore 1 4,436 4,543 5,924 Canada - Onshore 521 597 681 Total net natural gas liquids 10,827 9,583 11,222 Net natural gas – thousands of cubic feet per day United States - Onshore 33,415 25,028 25,863 United States - Offshore 1 51,793 57,228 70,239 Canada - Onshore 422,742 398,786 369,906 Total net natural gas 507,950 481,042 466,008 Total net hydrocarbons - including noncontrolling interest 2 188,838 184,063 192,178 Noncontrolling interest Net crude oil and condensate – barrels per day (5,837) (6,438) (6,200) Net natural gas liquids – barrels per day (217) (198) (220) Net natural gas – thousands of cubic feet per day (1,767) (1,942) (2,089) Total noncontrolling interest 2 (6,349) (6,960) (6,768) Total net hydrocarbons - excluding noncontrolling interest 2 182,489 177,103 185,410 1 Includes net volumes attributable to the noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 37 Table of Contents PART II
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued The following is a summarized statement of operations for E&P continuing operations: (Millions of dollars) 2024 2023 2022 Revenues and other income Revenue from production $ 3,014.9 $ 3,376.6 $ 4,038.5 Sales of purchased natural gas 3.7 72.2 181.7 Other income 6.0 8.0 26.7 Total revenues and other income 3,024.6 3,456.8 4,246.9 Costs and Expenses Lease operating expenses 937.0 784.4 679.3 Severance and ad valorem taxes 39.2 42.8 57.0 Transportation, gathering and processing 210.8 233.0 212.7 Costs of purchased natural gas 3.1 51.7 172.0 Depreciation, depletion and amortization 856.9 850.5 763.9 Impairments of assets 62.9 — — Accretion of asset retirement obligations 52.4 46.0 46.2 Total exploration expenses, including undeveloped lease amortization 133.5 234.8 133.1 Selling and general expenses 23.8 37.7 44.5 Other 0.3 56.9 141.8 Results of operations before taxes 704.7 1,119.0 1,996.4 Income tax provisions 106.3 237.8 417.3 Results of operations (excluding Corporate segment) 1 $ 598.4 $ 881.2 $ 1,579.1 1 Includes results attributable to a noncontrolling interest in MP GOM.
(Millions of dollars) 2025 2024 2023 Revenues and other income Revenue from production $ 2,689.8 $ 3,014.9 $ 3,376.6 Sales of purchased natural gas — 3.7 72.2 Gain on sale of assets and other operating income 17.6 6.0 8.0 Total revenues and other income 2,707.4 3,024.6 3,456.8 Costs and Expenses Lease operating expenses 765.2 937.0 784.4 Severance and ad valorem taxes 39.2 39.2 42.8 Transportation, gathering and processing 199.7 210.8 233.0 Costs of purchased natural gas — 3.1 51.7 Depreciation, depletion and amortization 969.4 856.9 850.5 Impairments of assets 115.0 62.9 — Accretion of asset retirement obligations 57.6 52.4 46.0 Total exploration expenses, including undeveloped lease amortization 111.7 133.5 234.8 Selling and general expenses 46.2 23.8 37.7 Other 16.5 0.3 56.9 Results of operations before taxes 386.9 704.7 1,119.0 Income tax expense 90.2 106.3 237.8 Results of operations (excluding Corporate segment) 1 $ 296.7 $ 598.4 $ 881.2 1 Includes results attributable to the noncontrolling interest in MP GOM. 34 Table of Contents PART II Item 7.
Magnolia Oil & Gas Corporation SM Energy Company Coterra Energy Inc. Marathon Oil Corporation 1 Southwestern Energy Company 1 Devon Energy Corporation Matador Resources Company Talos Energy Inc. EOG Resources Inc.
Range Resources Corporation Civitas Resources, Inc. Kosmos Energy Ltd. SM Energy Company Coterra Energy Inc. Magnolia Oil & Gas Corporation Talos Energy Inc. Devon Energy Corporation Matador Resources Company Diamondback Energy, Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2024: (Average price for the period) 2024 2023 2022 Oil and NGLs WTI ($/BBL) $ 75.72 $ 77.62 $ 94.23 Natural gas NYMEX ($/MMBTU) 2.24 2.53 6.38 AECO (C$/MCF) 1.46 2.64 5.31 Production Volumes The following table contains hydrocarbons produced during the three years ended December 31, 2024.
The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2025: (Average price for the period) 2025 2024 2023 Oil and NGLs WTI ($/BBL) $ 64.81 $ 75.72 $ 77.62 Natural gas Henry Hub ($/MMBTU) 3.54 2.24 2.53 AECO (C$/MCF) 1.68 1.46 2.64 35 Table of Contents PART II Item 7.
Please also refer to “ Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities ” in the Supplemental Oil and Natural Gas Information section for additional supporting tables. 33 Table of Contents PART II Item 7.
E&P Continuing Operations: 2025 vs 2024 The following section of E&P continuing operations excludes the Corporate segment, unless otherwise noted. Please also refer to “ Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities ” in the Supplemental Oil and Natural Gas Information section for additional supporting tables.
Lower revenues from production were primarily driven by mechanical and weather downtime in the Gulf of America, timing and performance of new wells at Eagle Ford Shale and lower average oil and natural gas prices, partially offset by wells brought back online at the non-operated Terra Nova field in the fourth quarter of 2023.
Lower revenues from production were primarily driven by lower average oil prices and lower volumes in the Gulf of America due to downtime and the natural decline of new wells, and was partially offset by increased production in the Eagle Ford Shale due to new wells and improved performance, as well as higher realized natural gas prices in Canada, at the Tupper Montney.
Civitas Resources Inc., EOG Resources Inc. and Magnolia Oil & Gas Corporation were added to Murphy’s peer group in 2024. Callon Petroleum Company, Hess Corporation and PDC Energy Inc. were removed from Murphy’s peer group in 2024.
Chord Energy Corporation, Diamondback Energy, Inc., Expand Energy Corporation and Permian Resources Corporation were added to Murphy’s peer group in 2025. Marathon Oil Corporation and Southwestern Energy Company were removed from Murphy’s peer group in 2025.
The decrease was principally due to lower production in the U.S., primarily in the Gulf of America due to downtime for wells awaiting workovers and in the Eagle Ford Shale due to timing and performance of new wells and partially offset by the restart of production at the non-operated Terra Nova field in Canada in the first quarter of 2024. 32 Table of Contents PART II Item 7.
Lower production in the Gulf of America related to planned and unplanned downtime and was partially offset by new wells online. 33 Table of Contents PART II Item 7.
Lower transportation, gathering and processing expenses related to lower production in the U.S. For the year ended December 31, 2024, total hydrocarbon production was 184,293 BOEPD, a decrease of 4% compared to 2023.
For the year ended December 31, 2025, total hydrocarbon production was 188,682 BOEPD, an increase of 2% compared to 2024. The increase was principally due to higher production in the Eagle Ford Shale and Canada Onshore and was partially offset by lower production in the Gulf of America.
Lower net income from continuing operations was largely driven by lower revenues and other income ($431.7 million), higher lease operating expenses ($152.7 million), and higher impairment expense ($62.9 million), partially offset by lower income tax expense ($117.6 million), lower exploration expenses ($101.2 million), higher other income ($79.5 million), lower other operating expense ($35.5 million) and lower transportation, gathering and processing costs ($22.2 million).
Lower net income from continuing operations was largely driven by lower revenues and other income ($309.7 million), higher depreciation, depletion and amortization expense (DD&A) ($112.0 million), higher other losses ($93.2 million), higher impairment expense ($52.1 million) and higher selling and general expenses ($27.2 million).
For further discussion on volumes, please see “ Revenues from Production ” section on page 37 .
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Production Volumes The following table contains hydrocarbons produced during the three years ended December 31, 2025. For further discussion on volumes, please see “ Revenues from Production ” section on page 38 .
Removed
Ovintiv Inc. 2019 2020 2021 2022 2023 2024 Murphy Oil Corporation 100 47 104 176 179 131 Peer Group 100 64 132 201 191 180 S&P 500 Index 100 118 152 125 158 197 XOP Index 100 65 121 192 192 181 1 Marathon Oil Corporation and Southwestern Energy Company were acquired in 2024 and therefore have been excluded from the above table and graph of cumulative total return. 30 Table of Contents PART II Item 6.
Added
Ovintiv Inc. 2020 2021 2022 2023 2024 2025 Murphy Oil Corporation 100 221 372 380 278 302 S&P 500 Index 100 129 105 133 166 196 2025 Peer Group 100 211 318 315 309 298 2024 Peer Group 100 206 314 297 281 265 XOP Index 100 187 297 297 281 283 31 Table of Contents PART II Item 6.
Removed
Higher lease operating expenses were primarily due to workovers in the Gulf of America and higher production activity in Canada at the Terra Nova field, partially offset by lower production handling fees in the Gulf of America. Higher impairment expense is due to impairment of the Calliope and Nearly Headless Nick fields in the Gulf of America.
Added
Subsequent to year end: • Issued $500.0 million of 6.50% senior notes due in 2034 and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028; • Upsized senior unsecured revolving credit facility from $1.35 billion to $2.00 billion and extended maturity from 2029 to 2031; • Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced a dry hole at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire; and • Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share. 1 Details of the capital allocation plan can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024.
Removed
The decrease in income tax expense is primarily driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend.
Added
These items were partially offset by lower lease operating expenses ($171.7 million), lower income tax expense ($33.7 million), and lower exploration expenses ($21.9 million).
Removed
Exploration expenses in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of America, including Sebastian #1 (Mississippi Canyon 387), non-operated Orange #1 (Mississippi Canyon 216), and for previously suspended exploration costs related to an expired lease at Hoffe Park #1 (Mississippi Canyon 166).
Added
Higher DD&A was primarily due to increased production and higher rates in the Eagle Ford Shale, and higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.
Removed
Higher other income related to unrealized foreign exchange gains and interest income on several outstanding joint interest receivables. Lower other operating expense in 2024 is primarily driven by lower non-operated Terra Nova field start-up costs, contingency adjustments and asset retirement obligations (ARO) revisions. Lower interest expense was due to lower debt levels.
Added
Higher other losses were mainly due to unrealized losses on foreign exchange related to our Canada business and were partially offset by lower interest expenses due to no debt repayment fees in the current year.
Removed
E&P Continuing Operations: 2024 vs 2023 The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.
Added
Impairment expense of $115.0 million in 2025 was related to the impairment of the Dalmatian property due to reserve reductions, as certain projects in the field were less competitive for capital allocation. Higher selling and general expenses were due to higher salary and compensation costs in 2025.
Added
Lower lease operating expenses were due to lower workovers in the current year, combined with lower operating costs related to the purchase of the Pioneer FPSO. Lower income tax expense was primarily attributable to lower taxable income and was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend.
Added
Lower exploration expenses were due to lower dry hole costs in the current period, which related to the Civette-1X (Block CI-502) exploration well in C ôte d’Ivoire, and was partially offset by higher exploration, geological, geophysical and other costs related to the Company’s U.S. Offshore and C ôte d’Ivoire exploration programs.
Added
Increased production in the Eagle Ford Shale was driven primarily by the performance of new wells online in the current year at Karnes and Catarina. Higher production in Canada Onshore related to better well performance at the Tupper Montney.
Added
The following is a summarized statement of operations for E&P continuing operations.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

94 edited+32 added−28 removed50 unchanged
Biggest changeYear Ended December 31, (Millions of dollars) 2024 2023 2022 Net (loss) income attributable to Murphy (GAAP) 1 $ 407.2 $ 661.6 $ 965.0 Income tax expense 78.3 195.9 309.5 Interest expense, net 105.9 112.4 150.8 Depreciation, depletion and amortization expense 1 833.1 836.7 748.2 EBITDA attributable to Murphy (Non-GAAP) 1,424.5 1,806.6 2,173.5 Impairment of assets 1 62.9 — — Accretion of asset retirement obligations 1 46.9 41.0 40.9 Foreign exchange (gain) loss (45.4) 10.8 (23.0) Write-off of previously suspended exploration well 26.1 17.1 22.7 Discontinued operations loss 2.8 1.5 2.1 Mark-to-market loss (gain) on derivative instruments 1.7 — (214.7) Mark-to-market loss on contingent consideration — 7.1 78.3 Asset retirement obligation losses — 16.9 30.8 Gain on sale of assets 1 — — (14.5) Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,519.5 $ 1,901.0 $ 2,096.1 1 Excludes amounts attributable to a noncontrolling interest in MP GOM. 45 Table of Contents PART II Item 7.
Biggest changeYear Ended December 31, (Millions of dollars) 2025 2024 2023 Net income attributable to Murphy (GAAP) 1 $ 104.2 $ 407.2 $ 661.6 Income tax expense 44.6 78.3 195.9 Interest expense, net 96.1 105.9 112.4 Depreciation, depletion and amortization expense ¹ 946.8 833.1 836.7 EBITDA attributable to Murphy (Non-GAAP) $ 1,191.7 $ 1,424.5 $ 1,806.6 Exploration expenses 1 111.6 133.5 204.6 EBITDAX attributable to Murphy (Non-GAAP) $ 1,303.3 $ 1,558.0 $ 2,011.2 EBITDA attributable to Murphy (Non-GAAP) $ 1,191.7 $ 1,424.5 $ 1,806.6 Impairment of asset 1 92.0 62.9 — Foreign exchange (gain) loss 29.4 (45.4) 10.8 Accretion of asset retirement obligations ¹ 51.5 46.9 41.0 Unrealized (gain) loss on derivative instruments (1.7) 1.7 — Write-off of previously suspended exploration well — 26.1 17.1 Asset retirement obligation losses — — 16.9 Unrealized loss on contingent consideration — — 7.1 Discontinued operations (income) loss (0.5) 2.8 1.5 Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,362.4 $ 1,519.5 $ 1,901.0 Other exploration expenses 2 111.6 107.4 187.5 Adjusted EBITDAX attributable to Murphy (Non-GAAP) $ 1,474.0 $ 1,626.9 $ 2,088.5 1 Excludes amounts attributable to the noncontrolling interest in MP GOM. 2 Other exploration expenses consist of exploration expenses as reported in the Consolidated Statements of Operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above. 45 Table of Contents PART II Item 7.
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.
In 2024, the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million. In the first quarter, the Company recognized an impairment expense of $34.5 million for the Calliope field. In the fourth quarter, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field.
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.
These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.
In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements.
In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and intent to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other environmental, social and governance matters, make capital expenditures, pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements.
Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions.
Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions.
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.
Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for oil and natural gas, (b) estimated reserves for oil and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements.
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.
Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ members’ production levels and/or attitudes of traders concerning supply and demand in the future. Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.
Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2025 using operating cash flow and available cash.
Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2026 using operating cash flow and available cash.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation plan designed to allow for additional shareholder returns and debt reduction.
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.
Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligation (ARO) liabilities.
Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations. We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing.
Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations. We cannot predict what impact economic factors (including, but not limited to, inflation, evolving trade policy, global conflicts and possible economic recession) may have on future commodity pricing.
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. 49 Table of Contents PART II Item 7.
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. 50 Table of Contents PART II Item 7.
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’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.
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.
Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheets to ensure that they are fairly presented.
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.
Total payments due after 2025 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.
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.
Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs. Based on bond yields as of December 31, 2025, the Company has used a weighted average discount rate of 5.40% at year end 2025 for the primary U.S. plans.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued The following table reconciles net income attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.
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.
A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity " on page 72 of this Form 10-K report. Other Balance Sheet Activity - Long-Term Assets and Liabilities Other significant changes in Murphy’s balance sheet at the end of 2025, compared to 2024 are discussed below.
In 2025, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 57%. If the prices for crude oil and natural gas are lower in 2025 or beyond, this will have an unfavorable impact on the Company’s operating profits; likewise, if prices are higher, this will have a favorable impact.
In 2026, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 56%. If the prices for crude oil and natural gas are lower in 2026 or beyond, this will have an unfavorable impact on the Company’s operating profits; likewise, if prices are higher, this will have a favorable impact.
Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022 and F orm 8-K filed on August 8, 2024. The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock.
Details of the plan can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024. The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock.
Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation and trade policies.
Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply and demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or markets of health pandemics and related government responses; natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; cyber attacks and other cybersecurity risks; any failure to obtain necessary regulatory approvals; the impact of current and future laws, rulings and governmental regulations; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions.
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.
The total reductions of operating cash flows for interest paid (which excludes “Early redemption of debt cost” reported in “Financing Activities”) during the two years ended December 31, 2025, and 2024 were $88.1 million and $78.8 million, respectively. Cash interest paid in 2025 was primarily due to interest payments on outstanding debt.
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.
As of December 31, 2025, the fixed-rate notes had a weighted average maturity of 8.3 years and a weighted average coupon of 6.1%. Refer to Note F for additional details.
Murphy’s 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.
Murphy’s disclosures related to its alignment with the TCFD framework are included in the Company’s 2025 Sustainability Report issued on August 6, 2025, which is not incorporated by reference hereto.
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.
In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $211.8 million as of December 31, 2025.
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.
Corporate: 2025 vs 2024 Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of natural gas sold) and corporate overhead not allocated to E&P.
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.
Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods. The Company’s proved reserves of oil and natural gas are presented on pages 111 to 120 of this Form 10-K report.
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.
See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2025 beginning on pages 4 and 111 of this Form 10-K report.
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. 50 Table of Contents PART II Item 7.
See Note F for additional information. Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Canada Onshore transportation and processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above. 51 Table of Contents PART II Item 7.
As discussed in the “ Results of Operations ” section on revenues, on page 37 , lower average crude oil price during 2024 directly impacted the Company’s product sales revenue.
As discussed in the “ Results of Operations ” section on revenues, on page 38 , lower average crude oil price during 2025 directly impacted the Company’s product sales revenue.
The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales. The Company currently expects average daily production in 2025 to be between 181,100 and 189,100 BOEPD (including a noncontrolling interest of 6,600 BOEPD).
The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales. The Company currently expects average daily production in 2026 to be between 173,000 and 181,000 BOEPD (including a noncontrolling interest of 6,000 BOEPD).
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.
This weighted average discount rate is 0.2% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 7.70% for the primary U.S. plan and periodically reconsiders the appropriateness of this and other key assumptions.
The Company 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued 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.
Lower prices, should they occur, will result in lower profits and operating cash flows. The Company’s capital expenditure spend for 2025 is expected to be between $1,135 million and $1,285 million, excluding noncontrolling interest. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.
Lower prices, should they occur, will result in lower profits and operating cash flows. The Company’s capital expenditure spend for 2026 is expected to be between $1,200 million and $1,300 million, excluding NCI. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.
Year Ended December 31, (Millions of dollars) 2024 2023 2022 Net income attributable to Murphy (GAAP) 1 $ 407.2 $ 661.6 $ 965.0 Discontinued operations loss 2.8 1.5 2.1 Net income from continuing operations attributable to Murphy 410.0 663.1 967.1 Adjustments: Impairment of assets 62.9 — — Write-off of previously suspended exploration well 26.1 17.1 22.7 Foreign exchange (gain) loss (45.4) 10.9 (23.0) Refinancing and early redemption of debt costs (non-cash) 3.7 — 10.3 Mark-to-market loss (gain) on derivative instruments 1.7 — (214.7) Asset retirement obligation losses — 16.9 30.8 Mark-to-market loss on contingent consideration — 7.1 78.3 (Gain) on sale of assets — — (14.5) Total adjustments, before taxes 49.0 52.0 (110.1) Income tax (benefit) expense related to adjustments (8.3) (6.4) 23.8 Tax (benefit) on investments in foreign areas (34.0) — — Total adjustments after taxes 6.7 45.6 (86.3) Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 416.7 $ 708.7 $ 880.8 Net income from continuing operations per average diluted share (GAAP) $ 2.72 $ 4.23 $ 6.14 Adjusted net income from continuing operations attributable to Murphy per average diluted share (Non-GAAP) $ 2.76 $ 4.52 $ 5.59 1 Excludes amounts attributable to a noncontrolling interest in MP GOM. 44 Table of Contents PART II Item 7.
Year Ended December 31, (Millions of dollars, except per share amounts) 2025 2024 2023 Net income attributable to Murphy (GAAP) 1 $ 104.2 $ 407.2 $ 661.6 Discontinued operations (income) loss (0.5) 2.8 1.5 Net income from continuing operations 103.7 410.0 663.1 Adjustments: Impairment of assets 1 92.0 62.9 — Foreign exchange (gain) loss 29.4 (45.4) 10.9 Unrealized (gain) loss on derivative instruments (1.7) 1.7 — Write-off of previously suspended exploration well — 26.1 17.1 Unrealized loss on contingent consideration — — 7.1 Asset retirement obligation losses — — 16.9 Refinancing and early redemption of debt costs (non-cash) — 3.7 — Total adjustments, before taxes 119.7 49.0 52.0 Income tax (benefit) expense related to adjustments (26.4) (8.3) (6.4) Tax benefits on investments in foreign areas — (34.0) — Total adjustments, after taxes 93.3 6.7 45.6 Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 197.0 $ 416.7 $ 708.7 Net income from continuing operations per average diluted share $ 0.72 $ 2.72 $ 4.23 Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 1.37 $ 2.76 $ 4.52 1 Excludes amounts attributable to the noncontrolling interest in MP GOM. 44 Table of Contents PART II Item 7.
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 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. 49 Table of Contents PART II Item 7.
If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels. Similar to the overall inflation and higher interest rates in the wider economy, the oil and natural gas industry and the Company are observing higher costs for goods and services used in E&P operations.
If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels. The oil and natural gas industry and the Company continue to observe higher costs for goods and services used in E&P operations.
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.
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 48 Table of Contents PART II Item 7.
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.
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.
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.
Realized and unrealized losses on derivative instruments result from increases in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price. Corporate activities reported a loss of $158.4 million in 2025, an unfavorable variance of $49.3 million compared to 2024.
Murphy had commitments for capital expenditures of approximately $417.0 million at December 31, 2024 (2023: $209.8 million).
Murphy had commitments for capital expenditures of approximately $551.2 million at December 31, 2025 (2024: $417.0 million).
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note F ).
The dividend is payable on March 2, 2026, to stockholders of record as of February 17, 2026. The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note F ).
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.
In 2025, the Company paid $25.1 million into various retirement plans and $12.9 million into postretirement plans. In 2026, the Company is expecting to fund payments of approximately $24.5 million into various retirement plans and $4.7 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years.
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.
Property, plant and equipment, net of depreciation, increased $81.7 million principally due to capital expenditures in the year, partially offset by DD&A expense ($977.8 million) and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the “ Cash Required by Investing Activities ” section.
Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income excludes certain items that management believes affects the comparability of results between periods.
Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.
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.
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 47 Table of Contents PART II Item 7.
Exploration Expenses The Company’s exploration expenses were as follows: (Millions of dollars) 2024 2023 2022 Exploration expenses Dry holes and previously suspended exploration costs $ 73.2 $ 169.8 $ 82.1 Geological and geophysical 27.2 26.1 10.4 Other exploration 23.5 28.0 27.3 Undeveloped lease amortization 9.6 10.9 13.3 Total exploration expenses $ 133.5 $ 234.8 $ 133.1 Exploration expenses in 2024 decreased by $101.3 million compared to 2023.
(Millions of dollars) 2025 2024 2023 Exploration expenses Dry holes and previously suspended exploration costs $ 30.1 $ 73.2 $ 169.8 Geological and geophysical 36.0 27.2 26.1 Other exploration 33.9 23.5 28.0 Undeveloped lease amortization 11.7 9.6 10.9 Total exploration expenses $ 111.7 $ 133.5 $ 234.8 Exploration expenses in 2025 decreased by $21.8 million compared to 2024.
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 2024, cash interest paid was primarily due to interest payments on outstanding debt and accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) for an aggregate redemption amount of $650.1 million.
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.
Both impairment charges were due to subsurface issues that led to reserve reductions. See also Note D for further discussion of impairment charges. Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates.
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.
Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.
The 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.
Financial Condition The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF, as described below.
Working Capital (Millions of dollars) December 31, 2024 December 31, 2023 Working capital Total current assets $ 785.3 $ 752.2 Total current liabilities 942.8 846.5 Net working capital liability $ (157.5) $ (94.3) As of December 31, 2024, net working capital had an unfavorable decrease of $63.2 million compared to December 31, 2023.
Working Capital (Millions of dollars) 2025 2024 Working capital Total current assets $ 816.7 $ 785.3 Total current liabilities 1,062.7 942.8 Net working capital liability $ (246.0) $ (157.5) As of December 31, 2025, net working capital had an unfavorable decrease of $88.5 million compared to December 31, 2024.
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: (Millions of dollars) (Dollars per equivalent barrel) 2024 2023 2022 2024 2023 2022 Lease operating expenses United States – Onshore $ 141.9 $ 150.3 $ 137.6 $ 13.02 $ 12.48 $ 10.94 United States – Offshore 608.0 480.4 385.1 21.38 14.46 13.19 Canada – Onshore 132.6 140.3 139.5 5.18 5.89 6.75 Canada – Offshore 52.9 11.5 15.6 22.43 12.30 14.20 Other 1.6 1.9 1.5 18.52 14.94 6.25 Total lease operating expenses $ 937.0 $ 784.4 $ 679.3 $ 13.91 $ 11.18 $ 10.65 Transportation, gathering and processing United States – Onshore $ 9.6 $ 12.7 $ 18.4 $ 0.88 $ 1.05 $ 1.47 United States – Offshore 121.3 144.3 123.8 4.27 4.34 4.24 Canada – Onshore 75.5 72.2 65.3 2.95 3.03 3.16 Canada – Offshore 4.4 3.8 5.2 1.85 4.12 4.76 Total transportation, gathering and processing $ 210.8 $ 233.0 $ 212.7 $ 3.13 $ 3.32 $ 3.34 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.
(Millions of dollars) (Dollars per equivalent barrel) 2025 2024 2023 2025 2024 2023 Lease operating expenses United States – Onshore $ 125.5 $ 141.9 $ 150.3 $ 9.15 $ 13.02 $ 12.48 United States – Offshore 451.6 608.0 480.4 17.78 21.38 14.46 Canada – Onshore 128.2 132.6 140.3 4.75 5.18 5.89 Canada – Offshore 57.4 52.9 11.5 21.12 22.43 12.30 Other 2.5 1.6 1.9 29.74 18.52 14.94 Total lease operating expenses $ 765.2 $ 937.0 $ 784.4 $ 11.10 $ 13.91 $ 11.18 Transportation, gathering and processing United States – Onshore $ 11.0 $ 9.6 $ 12.7 $ 0.81 $ 0.88 $ 1.05 United States – Offshore 96.0 121.3 144.3 3.78 4.27 4.34 Canada – Onshore 87.0 75.5 72.2 3.22 2.95 3.03 Canada – Offshore 5.7 4.4 3.8 2.08 1.85 4.12 Total transportation, gathering and processing $ 199.7 $ 210.8 $ 233.0 $ 2.90 $ 3.13 $ 3.32 Lease operating expenses and transportation, gathering and processing expenses in 2025 decreased by $171.8 million and $11.1 million, respectively, compared to 2024.
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 unfavorable variance was primarily due to a foreign exchange loss of $29.4 million in 2025 compared to a foreign exchange gain of $45.4 million in 2024, as a result of unrealized exchange rate changes relating to our Canadian subsidiary.
As of close on February 25, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the table below: 2025 2026 WTI ($/BBL) 67.60 64.93 NYMEX ($/MMBTU) 4.44 4.21 AECO (US$ Equivalent/MCF) 1.49 2.21 In 2024, liquids from continuing operations represented approximately 56% of total hydrocarbons produced on a barrels of oil equivalent basis.
As of close on February 23, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the table below. 2026 2027 NYMEX WTI ($/BBL) $ 64.90 $ 62.02 NYMEX Henry Hub ($/MMBTU) 3.39 3.72 AECO (US$ Equivalent/MCF) 1.36 1.90 In 2025, liquids from continuing operations represented approximately 55% of total hydrocarbons produced on a barrels of oil equivalent basis.
Depreciation, Depletion and Amortization Expense The Company’s depreciation, depletion and amortization expense by geographic area was as follows: (Millions of dollars) (Dollars per equivalent barrel) 2024 2023 2022 2024 2023 2022 Depreciation, depletion and amortization expense United States – Onshore $ 319.9 $ 316.7 $ 321.4 $ 29.36 $ 26.29 $ 25.55 United States – Offshore 389.3 389.3 295.6 13.69 11.72 10.12 Canada – Onshore 123.5 133.4 128.1 4.82 5.60 6.20 Canada – Offshore 22.5 8.8 13.4 9.55 9.47 12.25 Other 1.7 2.3 5.4 20.13 18.05 22.19 Total depreciation, depletion and amortization expense $ 856.9 $ 850.5 $ 763.9 $ 12.72 $ 12.12 $ 11.98 Depreciation, depletion and amortization expense (DD&A) in 2024 increased by $6.4 million compared to 2023.
(Millions of dollars) (Dollars per equivalent barrel) 2025 2024 2023 2025 2024 2023 Depreciation, depletion and amortization expense United States – Onshore $ 412.3 $ 319.9 $ 316.7 $ 30.02 $ 29.36 $ 26.29 United States – Offshore 409.8 389.3 389.3 16.13 13.69 11.72 Canada – Onshore 118.1 123.5 133.4 4.38 4.82 5.60 Canada – Offshore 26.7 22.5 8.8 9.81 9.55 9.47 Other 2.5 1.7 2.3 30.23 20.13 18.05 Total depreciation, depletion and amortization expense $ 969.4 $ 856.9 $ 850.5 $ 14.06 $ 12.72 $ 12.12 DD&A in 2025 increased by $112.5 million compared to 2024.
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.
As of December 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $152.5 million (2024: $95.2 million), the majority of which was held in Canada ($76.5 million), Brunei ($23.7 million), Côte d’Ivoire ($21.6 million), and Vietnam ($8.5 million).
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 $72.2 million (2026), $141.1 million (2027 - 2028), $81.0 million (2029 - 2030) and $235.9 million (After 2030) for pipeline transportation commitments in Canada. Also includes $3.7 million (2026), $7.5 million (2027 - 2028), $7.4 million (2029 - 2030) and $14.3 million (After 2030) for long-term take-or-pay commitments relating to natural gas processing in Canada.
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.
Liquidity At December 31, 2025, the Company had approximately $1.6 billion of liquidity consisting of $377.2 million in cash and cash equivalents and $1,249.6 million available on its previous RCF with a major banking consortium.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Environmental, Health and Safety Matters Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons.
Offshore, including amounts attributable to the noncontrolling interest in MP GOM. 46 Table of Contents PART II Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Environmental, Health and Safety Matters Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons.
(Millions of dollars) 2024 2023 2022 Net cash provided by (required by): Net cash provided by continuing operations activities $ 1,729.0 $ 1,748.8 $ 2,180.2 Net cash required by investing activities (908.2) (998.7) (1,109.4) Net cash required by financing activities (716.5) (923.7) (1,081.6) Net cash required by discontinued operations — — (14.5) Effect of exchange rate changes on cash and cash equivalents 2.2 (1.2) (3.9) Net (decrease) increase in cash and cash equivalents $ 106.5 $ (174.8) $ (29.2) Cash Provided by Continuing Operations Activities Net cash provided by continuing operations activities in 2024 was $19.8 million lower compared to 2023.
(Millions of dollars) 2025 2024 2023 Net cash provided by (required by): Net cash provided by continuing operations activities $ 1,247.8 $ 1,729.0 $ 1,748.8 Net cash required by investing activities (1,028.9) (908.2) (998.7) Net cash required by financing activities (264.1) (716.5) (923.7) Effect of exchange rate changes on cash and cash equivalents (1.2) 2.2 (1.2) Net (decrease) increase in cash and cash equivalents $ (46.4) $ 106.5 $ (174.8) 40 Table of Contents PART II Item 7.
Year Ended December 31, (Millions of dollars) 2024 2023 2022 Property additions and dry hole costs per cash flow statements $ 908.2 $ 1,066.0 $ 985.5 Geophysical and other exploration expenses 44.8 46.0 30.6 Acquisition of oil and natural gas properties per the cash flow statements — 35.6 128.5 Capital expenditure accrual changes and other 11.8 (9.5) 38.6 Total capital expenditures $ 964.8 $ 1,138.1 $ 1,183.2 40 Table of Contents PART II Item 7.
Year Ended December 31, (Millions of dollars) 2025 2024 2023 Property additions and dry hole costs per cash flow statements $ 1,020.6 $ 900.1 $ 1,066.0 Geophysical and other exploration expenses 65.6 44.8 46.0 Acquisition of oil and natural gas properties per the cash flow statements 29.0 8.1 35.6 Capital expenditure accrual changes and other 102.8 11.8 (9.5) Total capital expenditures $ 1,218.0 $ 964.8 $ 1,138.1 Total capital expenditures categorized by E&P and corporate activities are presented below.
December 31, 2024 December 31, 2023 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 1,274.5 19.7 % $ 1,328.4 19.9 % Murphy shareholders' equity 5,194.3 80.3 % 5,362.8 80.1 % Total capital employed $ 6,468.8 100.0 % $ 6,691.2 100.0 % As of December 31, 2024, long-term debt decreased by $53.9 million compared to December 31, 2023, as a result of the repurchase of the 2027 Notes and 2028 Notes.
December 31, 2025 December 31, 2024 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 1,382.6 21.3 % $ 1,274.5 19.7 % Murphy shareholders' equity 5,118.4 78.7 % 5,194.3 80.3 % Total capital employed $ 6,501.0 100.0 % $ 6,468.8 100.0 % As of December 31, 2025, long-term debt increased by $108.1 million compared to December 31, 2024, primarily as a result of amounts drawn on the RCF.
In certain cases, the Company could incur cash taxes or other costs should these cash balances be 41 Table of Contents PART II Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
In addition, approximately $7.8 million and $7.0 million of cash was held in Mexico and the U.K., respectively. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
It was utilized in certain undrilled acreage at distances 47 Table of Contents PART II Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued 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.
In 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties.
In 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties. The Company recognized impairments of $34.5 million, related to the Calliope field, and $28.4 million, related to the Nearly Headless Nick field, both in the Gulf of America.
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.
Also includes $23.6 million (2026), $47.1 million (2027 - 2028), $48.1 million (2029 - 2030) and $176.8 million (After 2030) for the purpose of supporting future production activities in Vietnam. 2 Other long-term liabilities includes debt interest and future cash outflows for ARO liabilities.
Both fields were impaired as a result of operational issues that led to reserve reductions. There were no impairments recorded in 2023.
Both fields were impaired as a result of operational issues that led to reserve reductions. Exploration Expenses The Company’s exploration expenses were as follows.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued Revenues from Production The Company’s production revenues by country and product were as follows: (Millions of dollars) 2024 2023 2022 Revenues from production United States - Oil $ 2,364.3 $ 2,748.5 $ 3,085.9 United States - Natural gas liquids 71.7 80.6 124.4 United States - Natural gas 67.8 92.7 225.3 Canada - Oil 264.8 156.7 249.2 Canada - Natural gas liquids 7.4 8.9 18.3 Canada - Natural Gas 232.3 278.2 312.6 Other - Oil 6.6 11.0 22.8 Total revenues from production $ 3,014.9 $ 3,376.6 $ 4,038.5 Revenues from production in 2024 decreased by $361.7 million compared to 2023.
(Millions of dollars) 2025 2024 2023 Revenues from production United States - Oil $ 1,972.9 $ 2,364.3 $ 2,748.5 United States - Natural gas liquids 74.5 71.7 80.6 United States - Natural gas 106.5 67.8 92.7 Canada - Oil 248.8 264.8 156.7 Canada - Natural gas liquids 5.6 7.4 8.9 Canada - Natural Gas 275.8 232.3 278.2 Other - Oil 5.7 6.6 11.0 Total revenues from production $ 2,689.8 $ 3,014.9 $ 3,376.6 Revenues from production in 2025 decreased by $325.1 million compared to 2024.
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.
The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2026 are expected to be $0.4 million lower than in 2025 primarily due to higher actual return on plan assets, partially offset by an increase in the benefit obligations at December 31, 2025 compared to the prior year.
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 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.
Murphy’s shareholders’ equity decreased by $168.5 million in 2024 primarily due to cash dividends paid ($180.0 million), shares repurchased ($302.7 million, including excise tax), and foreign currency translation losses ($134.7 million), partially offset by net income earned ($407.2 million).
Murphy’s shareholders’ equity decreased by $75.9 million in 2025 primarily due to dividends ($186.2 million) and shares repurchased ($100.8 million), including excise tax, partially offset by foreign currency translation ($74.0 million), net income ($104.2 million), and awarded restricted stock ($22.4 million).
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.
The increase was primarily due to higher sales volumes and higher rates in the Eagle Ford Shale, higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.
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.
The Company’s previous $1.35 billion RCF was set to expire in October 2029, and as of December 31, 2025, the Company had $100.0 million outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. Borrowings under the RCF were subject to certain interest rates.
Non-current operating lease liabilities decreased $14.5 million primarily due to 2024 annual payments reducing operating lease liabilities for drilling rig and vessel commitments. Deferred income tax liabilities increased $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax effect s. 43 Table of Contents PART II Item 7.
Operating lease assets increased $27.9 million principally due to lease additions in Vietnam, partially offset by the depreciation of these assets. Deferred income tax liabilities increased $42.5 million due to utilization of our net operating loss, partially offset by other capital-related tax effects. 43 Table of Contents PART II Item 7.
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 prices are also affected by supply and demand factors, which are often influenced by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas. Natural gas prices can also be impacted by the demand for lower-carbon energy sources.
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).
The decrease was primarily attributable to higher accounts payable ($100.0 million), higher operating lease liabilities ($25.6 million), and a lower cash balance ($46.4 million), partially offset by higher accounts receivable ($74.2 million). Higher accounts payable were primarily due to the timing of payments for certain drilling activities and ongoing workover projects.
Cash Required by Investing Activities Net cash required by investing activities in 2024 was $90.5 million lower compared to 2023.
Cash Required by Financing Activities Net cash required by financing activities in 2025 decreased by $452.4 million compared to 2024.
As of February 25, 2025, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices, as follows: Volumes (MMCF/d) Price/MCF Remaining Period Area Commodity Type Start Date End Date Canada Natural Gas Fixed price forward sales 40 C$2.75 1/1/2025 12/31/2025 Canada Natural Gas Fixed price forward sales 50 C$3.03 1/1/2026 12/31/2026 Volumes (MMCF/d) Price/MCF Remaining Period Area Commodity Type Start Date End Date United States Natural Gas Fixed price derivative swap 40 US$3.58 2/1/2025 6/30/2025 United States Natural Gas Fixed price derivative swap 60 US$3.65 7/1/2025 9/30/2025 United States Natural Gas Fixed price derivative swap 60 US$3.74 10/1/2025 12/31/2025 52 Table of Contents PART II Item 7.
Volumes (MMCF/D) Price/MCF Remaining Period Area Commodity Type Start Date End Date Canada Natural Gas Fixed price forward sales 50 C$3.03 1/1/2026 3/31/2026 Canada Natural Gas Fixed price forward sales 78 C$2.94 4/1/2026 6/30/2026 Canada Natural Gas Fixed price forward sales 78 C$2.94 7/1/2026 9/30/2026 Canada Natural Gas Fixed price forward sales 59 C$3.00 10/1/2026 12/31/2026 Canada Natural Gas Fixed price forward sales 9.5 C$3.14 1/1/2027 12/31/2027 53 Table of Contents PART II Item 7.
(Millions of dollars) Amount of Obligations Total 2025 2026 - 2027 2028 - 2029 After 2029 Debt, excluding interest $ 1,284.8 $ — $ 78.9 $ 266.2 $ 939.7 Operating and finance leases 1,009.6 291.7 192.5 118.0 407.4 Capital expenditures, drilling rigs and other ¹ 1,294.4 469.8 339.2 160.2 325.2 Other long-term liabilities, including debt interest ² 2,618.0 197.2 262.0 194.9 1,963.9 Total $ 6,206.8 $ 958.7 $ 872.6 $ 739.3 $ 3,636.2 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.
(Millions of dollars) Amount of Obligations Total 2026 2027 - 2028 2029 - 2030 After 2030 Debt, excluding finance leases and interest $ 1,384.8 $ — $ 227.5 $ 217.5 $ 939.8 Operating and finance leases 1,024.8 318.9 215.8 123.0 367.1 Capital expenditures, drilling rigs and other ¹ 1,648.0 761.1 252.0 160.2 474.7 Other long-term liabilities, including debt interest ² 2,344.6 129.6 230.6 450.2 1,534.2 Total $ 6,402.2 $ 1,209.6 $ 925.9 $ 950.9 $ 3,315.8 1 Capital expenditures, drilling rigs and other includes $28.1 million, $25.4 million, $7.7 million, $1.0 million and $0.6 million in 2026 for approved capital projects in non-operated interests in the Gulf of America, the Eagle Ford Shale, Canada Offshore, Brunei, and Canada Onshore, respectively.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

1 edited+2 added−3 removed1 unchanged
Biggest changeCommodity Price Risk There were commodity transactions in place as of December 31, 2024, covering certain future U.S. natural gas sales volumes in 2025.
Biggest changeCommodity Price Risk There were no commodity transactions in place as of December 31, 2025, covering certain future U.S. oil and natural gas sales. Foreign Exchange Risk There were no derivative foreign exchange contracts in place as of December 31, 2025. Interest Rate Risk At December 31, 2025, long-term debt was $1,382.6 million.
Removed
A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately $2.5 million, while a 10% decrease would have decreased the recorded payable by a similar amount, resulting in a receivable.
Added
The fixed-rate notes have a weighted average coupon of 6.1%. The Company’s previous and Amended RCF agreements provide for variable interest rate borrowings. As of December 31, 2025, we had $100.0 million outstanding under the previous RCF, and a 10% increase in the average interest rate would have increased our quarterly interest expense by approximately $0.3 million.
Removed
Foreign Exchange Risk There were no derivative foreign exchange contracts in place as of December 31, 2024. Interest Rate Risk At December 31, 2024, long-term debt was $1,274.5 million. The fixed-rate notes have a weighted average coupon of 6.1%.
Added
Actual results may vary due to changes in the amount of variable rate debt outstanding.
Removed
The Company’s RCF provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of December 31, 2024 and, therefore, no related exposure to interest rate risk.

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