MURPHY OIL CORP

The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted.

Revenues from Production

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

Revenues from production for the three months ended September 30, 2025, decreased by $32.2 million compared to the same period in 2024. Revenues decreased primarily due to lower crude oil prices, reduced oil production in the Gulf of America from downtime relating to planned maintenance and ongoing workovers, and downtime in offshore Canada at Terra Nova and Hibernia related to well issues in the quarter. These reductions were partially offset by higher production at Karnes and Catarina in the Eagle Ford Shale related to better well performance and new wells online, and higher sales volumes at Cascade & Chinook in the Gulf of America.

Revenues from production for the nine months ended September 30, 2025, decreased $268.5 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline of new wells, and downtime for maintenance at Khaleesi. These decreases were partially offset by increased production in Eagle Ford Shale due to new wells at Karnes and Catarina, as well as in the Gulf of America at Mormont and Neidermeyer.

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:

For the three months ended September 30, 2025, lease operating expenses decreased by $38.5 million and transportation, gathering and processing expenses increased by $0.6 million compared to the same period in 2024. In the Gulf of America, decreases in lease operating expenses primarily related to lower production volumes and handling fees and lower operating charges as a result of the acquisition of the BW Pioneer FPSO. In addition, current quarter workover costs at Marmalard, Khaleesi and Samurai were lower than expenditures at Neidermeyer and Dalmatian in the prior year. In the Eagle Ford Shale, lower operating expenses were due to cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization throughout the year, and were largely offset by higher production.

For the nine months ended September 30, 2025, lease operating expenses decreased by $111.8 million, and transportation, gathering and processing expenses decreased by $6.4 million compared to the same period in 2024. In the Gulf of America, decreases primarily related to lower workover costs due to expenditures at Neidermeyer and Dalmatian in the prior year, which were partially offset by current year workovers at Marmalard, Khaleesi and Samurai. Lower operating charges also occured as a result of the acquisition of the BW Pioneer FPSO earlier in the year. In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, were partially offset by higher volume related costs.

Depreciation, Depletion and Amortization Expenses

The Company’s DD&A by geographic area were as follows:

DD&A for the three months ended September 30, 2025 increased by $59.3 million compared to the same period in 2024. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

DD&A for the nine months ended September 30, 2025 increased by $87.4 million. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

Impairment of Assets

For the three and nine months ended September 30, 2025, the Company impaired assets for $115.0 million related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions in the quarter, as certain projects in the field were less competitive for capital allocation.

There were no impairments for the three months ended September 30, 2024. Impairment of assets for the nine months ended September 30, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

Exploration Expenses

The Company’s exploration expenses were as follows:

Exploration expenses for the three months ended September 30, 2025 increased by $1.3 million compared to the same period in 2024 due to higher geological and geophysical costs in the Gulf of America, and were partially offset by lower dry hole costs in the current period. Dry hole costs in 2024 related to the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

Exploration expenses for the nine months ended September 30, 2025 decreased by $61.0 million compared to the same period in 2024. Lower exploration costs were primarily due to no dry holes recorded in 2025 (2024: Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America). This was partially offset by higher exploration activity in Côte d'Ivoire.

Other

Other expenses from E&P continuing operations for the three months ended September 30, 2025 decreased by $0.1 million compared to the same period in 2024. Other expenses for the nine months ended September 30, 2025 increased by $17.7 million compared to the same period in 2024 due to no interest income received in the current year.

Income Taxes

Income taxes for the three and nine months ended September 30, 2025 decreased by $3.0 million and $24.0 million, respectively, compared to the same periods in 2024. Lower income tax for each period is primarily the result of lower net income.

Corporate

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

For the three months ended September 30, 2025, the Corporate segment reported a loss of $18.6 million, a favorable variance of $15.1 million, compared to the same period in 2024. The favorable variance was primarily due to a foreign exchange gain ($18.4 million) for the period, primarily relating to our Canadian subsidiary, combined with gains on derivative instruments ($3.9 million), and partially offset by higher income tax expense of $5.1 million.

The Corporate segment reported a loss of $122.7 million for the nine months ended September 30, 2025, an unfavorable variance of $33.8 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher foreign exchange losses ($31.5 million) and higher interest expense ($11.4 million) due to the timing of interest payments on long-term debt, and was partially offset by gains on derivative instruments ($8.4 million) due to fixed price sales contracts.

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. The Company’s liquidity requirements, both in the short-term and long-term, consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next twelve months and the foreseeable future.

Cash Flows

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

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the nine months ended September 30, 2025 was $297.3 million lower compared to the same period in 2024. The decrease in cash flows from operations activities was primarily due to lower revenue from production ($268.5 million), timing of non-cash working capital ($52.3 million) settlements, and an increase in selling and general expenses ($19.8 million), partially offset by lower lease operating expenses ($111.8 million).

Cash Required by Investing Activities

Net cash required by investing activities for the nine months ended September 30, 2025 was $118.1 million higher compared to the same period in 2024. The increase was primarily due to a gross payment of $125.0 million for the purchase of an FPSO in the Gulf of America and higher development drilling at Eagle Ford Shale, partially offset by lower development drilling at Gulf of America.

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

Total accrual basis capital expenditures are shown below.

Higher capital expenditures in the nine months ended September 30, 2025 compared to the same period of 2024 were primarily attributable to the FPSO purchase in the Gulf of America and higher development drilling in the Eagle Ford Shale related to new wells online. Also contributing to the increase were higher exploratory drilling and field development in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower exploration costs and development drilling costs in the Gulf of America due to prior year spend on the non-operated Ocotillo #1 (Mississippi Canyon 40) and Orange #1 (Mississippi Canyon 216) exploration wells, and Khaleesi development costs, respectively.

Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($257.6 million), Eagle Ford Shale ($296.4 million), Tupper Montney and Kaybob Duvernay ($113.0 million), and in Vietnam ($57.7 million). Exploration costs in 2025 were $90.9 million, primarily comprised of activities in Vietnam for 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, activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d'Ivoire related to long lead equipment purchases for the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.

Cash Required by Financing Activities

Net cash required by financing activities for the nine months ended September 30, 2025 decreased by $464.9 million compared to the same period in 2024.

In 2025, the cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.975 per share ($139.8 million), and distributions to the noncontrolling interest in MP GOM ($43.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($150.0 million).

In 2024, cash required by financing activities was for the repurchase of common shares ($300.1 million), cash dividends to shareholders ($136.2 million), distributions to the noncontrolling interest in MP GOM ($96.6 million), debt repurchases ($50.0 million), and withholding tax on stock-based incentive awards ($25.3 million).

Liquidity

At September 30, 2025, the Company had approximately $1.6 billion of liquidity consisting of $426.0 million in cash and cash equivalents and $1,199.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029. As of September 30, 2025, the Company had $150.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48%. At September 30, 2025, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $67.4 million, the majority of which was held in Canada ($28.9 million), Mexico ($8.0 million), the U.K. ($7.4 million) and Vietnam ($6.7 million). 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.

Working Capital

As of September 30, 2025, net working capital increased by $107.3 million compared to December 31, 2024. The increase was primarily attributable to lower current operating lease obligations ($42.4 million), lower accounts payable ($42.5 million), and higher accounts receivable ($11.2 million).

Lower lease obligations were due to lower day rates related to an offshore drilling rig, ongoing lease amortization and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America.

Higher accounts receivable were due to higher tax receivables related to increased Vietnam development and exploration expenditures. Lower cash and equivalents were due to lower net income, the BW Pioneer FPSO purchase, and returns to shareholders in the form of share repurchases and dividends. Lower accounts payable related to higher production in the Eagle Ford Shale.

Capital Employed

A summary of capital employed at September 30, 2025 and December 31, 2024 follows.

At September 30, 2025, long-term debt of $1,425.2 million increased by $150.7 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF. The total of the fixed-rate notes had a weighted average maturity of 8.6 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $72.9 million in 2025, primarily due to dividends ($139.8 million) and shares repurchased ($100.9 million), including excise tax, partially offset by net income ($92.3 million), foreign currency translation ($50.5 million), and awarded restricted stock ($20.3 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of September 30, 2025, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2024.

Accounting Changes and Recent Accounting Pronouncements

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

Other Key Performance Metrics

The Company uses other operational performance and income metrics to review operational performance.

Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

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

Other Key Performance Metrics (Continued)

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

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

2 Other exploration expenses consist of exploration expenses as reported in the consolidated statement of operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.

Other Key Performance Metrics (Continued)

Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and Adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.

The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.

1 Property additions for the 2025 period include a payment of $125.0 million for the purchase of a floating production, storage, and offloading vessel in the U.S Offshore, including amounts attributable to a noncontrolling interest in MP GOM.

Outlook

The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the “Results of Operations” section discussing revenues, on page 36, lower average crude oil and higher natural gas pricing during the third quarter of 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on November 3, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the following table.

In late June 2025, Shell Canada Energy announced its first cargo of liquefied natural gas (LNG) shipped from the Kitimat facility in British Columbia. Increases in export levels of Canadian liquefied natural gas would impact our natural gas-weighted Canadian business.

In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. In August 2025, however, the U.S. Court of Appeals for the Federal Circuit ruled that many of the tariffs imposed under the Trump Administration exceed presidential authority and therefore are invalid, though the decision has been stayed pending U.S. Supreme Court review. This ruling introduces additional uncertainty as to the scope and durability of existing and future tariff measures. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate. Although we are continuing to monitor the economic effects of such announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations. Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.

For the fourth quarter of 2025, production is expected to average between 176.0 and 184.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company’s capital expenditures for 2025 are expected to be between $1,135 million and $1,285 million, excluding noncontrolling interest. This includes net acquisition capital of $104 million for the BW Pioneer FPSO in the Gulf of America, and excludes $23.0 million for the purchase of additional working interests in Eagle Ford Shale acreage primarily operated by Murphy. The Company remains on schedule to commence a three-well exploration program in Côte d’Ivoire in the fourth quarter of 2025, consisting of the Civette-1X (Block CI-502), Caracal-1X (Block CI-102), and Bubale-1X (Block CI-709) wells. Murphy is also continuing the drilling of the Hai Su Vang-2X (Golden Sea Lion) appraisal well in Block 15-2/17, offshore Vietnam, with results anticipated in the fourth quarter. The Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America will also be drilled in the fourth quarter of 2025. Finally, we will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with scheduled first oil anticipated in the fourth quarter of 2026.

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. 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. If oil and/

Outlook (Continued)

or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company plans to utilize any 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. Details of the plan can be found in the “Capital Allocation” section of the Company’s Form 8-K filed on May 7, 2025. Based on current market conditions and our planned exploration and appraisal program, the Company is currently more likely to use available adjusted Free Cash Flow for share repurchases than bond repayment.

On July 4, 2025, the current U.S. Administration signed into law the OBBBA legislation, which includes a broad range of tax reform provisions affecting corporations. The OBBBA, among other changes, permanently reinstates the "bonus" depreciation provisions that allow for the immediate expensing of 100% of the cost of certain qualified property acquired and placed in service after January 19, 2025, permanently reinstates the elective immediate expensing of domestic research and experimental expenditures paid or incurred in tax years beginning after December 31, 2024 (with a special transition rule that allows accelerated deduction of the remaining unamortized balance of capitalized domestic research and experimental expenditures), and permanently relaxes the limitation on the deductibility of business interest effective for tax years beginning after December 31, 2024. The OBBBA also modifies certain international tax provisions effective for tax years beginning after December 31, 2025. The Company evaluated the effects of the OBBBA in accordance with ASC 740, Income Taxes, and determined that the legislation did not have a material impact on its consolidated financial statements for the period ended September 30, 2025. The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA.

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of September 30, 2025.

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 senior unsecured RCF (see Note E).

As of November 3, 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:

1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.