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 June 30, 2025, decreased by $114.4 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, combined with decreased oil production in the Gulf of America due to downtime related to workovers, planned turnarounds and well issues, primarily at the Samurai and Cascade & Chinook fields. These items were partially offset by higher natural gas prices, new wells online in the Eagle Ford Shale at the Karnes field, new wells online at Mormont in the Gulf of America, wells back online from downtime in the Gulf of America, and timing of deliveries in Canada Offshore.

Revenues from production for the six months ended June 30, 2025, decreased $236.3 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, combined with decreased oil production in the Gulf of America due to downtime related to workovers, planned turnarounds and well issues, primarily at the Samurai and Cascade & Chinook fields. These items were partially offset by higher natural gas prices, new wells online in the Eagle Ford Shale and Gulf of America, as well as wells back online from downtime in the Gulf of America, and timing of deliveries in Canada Offshore.

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 June 30, 2025, lease operating expenses decreased by $44.1 million and transportation, gathering and processing expenses increased by $0.5 million compared to the same period in 2024. In the Gulf of America, current quarter workovers at Marmalard, Khaleesi (completed in Q3 2025) and Samurai (completed in Q2 2025) were lower than expenditures at Neidermeyer in the prior year. In the Eagle Ford Shale, there were lower operating costs resulting from cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization. The Company also realized lower operating costs at the U.S. Offshore Cascade & Chinook fields that resulted from the purchase of the FPSO. In addition, lower Gulf of America production handling fees, resulting from lower production, contributed to the decrease in the quarter. These decreases were partially offset by higher production volumes from both the U.S. Onshore and Canada Onshore areas.

For the six months ended June 30, 2025, lease operating expenses decreased by $73.3 million, and transportation, gathering and processing expenses decreased by $7.1 million compared to the same period in 2024. In the Gulf of America, workover costs at the Khaleesi, Mormont and Samurai fields were lower than expenditures at the Neidermeyer field in the prior 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 optimization. The Company also realized lower operating costs at the U.S. Offshore Cascade & Chinook fields that resulted from the purchase of the FPSO. In addition, lower Gulf of America production handling fees, resulting from lower production, contributed to the decrease in the period. These decreases were partially offset by higher production volumes from both the U.S. Onshore and Canada Onshore areas.

Depreciation, Depletion and Amortization Expenses

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

DD&A for the three months ended June 30, 2025 increased by $44.7 million compared to the same period in 2024. The increase was primarily due to higher sales volumes at both U.S. and Canada Onshore areas, in addition to higher rates at U.S. Offshore.

DD&A for the six months ended June 30, 2025 increased by $28.2 million. The increase was primarily due to higher sales volumes in the Eagle Ford Shale as a result of new wells and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

Impairment of Assets

There were no impairments for the three and six months ended June 30, 2025, as well as no impairments for the three months ended June 30, 2024.

Impairment of assets for the six months ended June 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 June 30, 2025 decreased by $32.4 million compared to the same period in 2024, primarily as a result of lower dry hole costs in the current period. In the second quarter of 2024, the dry hole costs related to the Orange #1 (Mississippi Canyon 216) non-operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

Exploration expenses for the six months ended June 30, 2025 decreased by $62.3 million compared to the same period in 2024. In 2024, there were dry holes and previously suspended exploration costs relating to the Orange

#1 (Mississippi Canyon 216) non-operated exploration well and for the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America.

Income Taxes

Income taxes for the three and six months ended June 30, 2025 decreased by $22.8 million and $20.9 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 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.

For the three months ended June 30, 2025, the Corporate segment reported a loss of $55.9 million, an unfavorable variance of $28.2 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher unrealized foreign exchange losses ($39.8 million) primarily relating to our Canadian subsidiary, partially offset by unrealized gains on derivative instruments ($10.3 million).

The Corporate segment reported a loss of $104.1 million for the six months ended June 30, 2025, an unfavorable variance of $48.9 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher unrealized foreign exchange losses ($50.0 million).

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 12 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 six months ended June 30, 2025 was $207.7 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 ($236.3 million), partially offset by lower lease operating expenses ($73.3 million).

Cash Required by Investing Activities

Net cash required by investing activities for the six months ended June 30, 2025 was $162.6 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 six months ended June 30, 2025 compared to the same period of 2024 were primarily attributable to higher field development costs in the Gulf of America attributable to the FPSO purchase and higher development drilling in the Eagle Ford Shale related to new wells online. Higher exploratory drilling in Vietnam and other development drilling in the Gulf of America also contributed to the increase. 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 ($248.1 million), Eagle Ford Shale ($230.2 million), Tupper Montney and Kaybob Duvernay ($92.0 million), and in Vietnam ($29.6 million). Exploration costs in 2025 were $57.2 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, and 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.

Cash Required by Financing Activities

Net cash required by financing activities for the six months ended June 30, 2025 decreased by $311.9 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 $0.65 per share ($93.4 million), and distributions to the noncontrolling interest in MP GOM ($18.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($200.0 million).

In 2024, cash required by financing activities was for the repurchase of common shares ($105.9 million), cash dividends to shareholders ($91.5 million), distributions to the noncontrolling interest in MP GOM ($61.2 million), debt repurchases ($50.0 million), and withholding tax on stock-based incentive awards ($25.3 million).

Liquidity

At June 30, 2025, the Company had approximately $1.5 billion of liquidity consisting of $379.6 million in cash and cash equivalents and $1,149.6 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 June 30, 2025, the Company had $200.0 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 June 30, 2025, the interest rate in effect on borrowings under the RCF was 6.67%. At June 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 June 30, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $112.4 million, the majority of which was held in Canada ($73.6 million), Vietnam ($9.0 million), Mexico ($8.0 million), and the U.K. ($7.7 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 June 30, 2025, net working capital increased by $10.4 million compared to December 31, 2024. The increase was primarily attributable to lower current operating lease obligations ($62.5 million), lower other accrued liabilities ($33.5 million), and higher prepaid expenses ($11.6 million). These items were partially offset by lower cash and equivalents ($43.9 million), higher accounts payable ($37.1 million) and higher current asset retirement obligations ($22.0 million).

Lower lease obligations were due to lower day rates on the Noble Stanley Lafosse drilling rig and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America. Lower other accrued liabilities were related to lower incentive award obligations in the current year, and higher prepaid expenses were primarily due to the renewal of insurance policies. 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. Higher accounts payable related to higher production in the Eagle Ford Shale. Higher current asset retirement obligations related to planned abandonment activities in U.S. Offshore in the next 12 months.

Capital Employed

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

At June 30, 2025, long-term debt of $1,475.0 million increased by $200.5 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 8.9 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity increased by $4.2 million in 2025, primarily due to foreign currency translation ($88.6 million) and awarded restricted stock ($20.1 million), partially offset by shares repurchased ($100.9 million, including excise tax). 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 June 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 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 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 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. Adjusted FCF excludes certain items that management believes affect the comparability of results between periods. 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 33, lower average crude oil and higher natural gas pricing during the second quarter of 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on August 4, 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. 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, 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 third quarter of 2025, production is expected to average between 185.0 and 193.0 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 Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America will be drilled in the third and fourth quarters of 2025. The Company remains on schedule to commence a three-well exploration program in Côte d’Ivoire in the fourth quarter of 2025. We will also begin drilling an appraisal well at our recent Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 oil discovery well in the third quarter, with results expected in the fourth quarter. In addition, we 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/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.

Outlook (Continued)

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.

Subsequent to the balance sheet date, 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 is currently evaluating the impact of these tax law changes and will recognize the income tax effects in the consolidated financial statements beginning in the period in which the OBBBA was signed into law.

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 June 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 August 4, 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.