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 March 31, 2025 decreased by $121.9 million compared to the same period in 2024. Revenue was lower in the Gulf of America, mostly driven by workover and turnaround-related downtime, well performance, and lower sales volumes at Cascade and Chinook fields as a result of the timing of sales cargos, partially offset by new well production at the Mormont field. Lower crude oil pricing was partially offset by higher natural gas pricing in the Gulf of America. Eagle Ford Shale revenues decreased due to natural decline, as well as lower crude oil prices. Revenues in Canada Offshore increased due to higher sales volumes at non-operated Terra Nova as a result of lower production in the first quarter of 2024 with production build-up after the completion of the asset life extension project, lower crude oil pricing, and the timing of sales cargos in 2025. Canada Onshore revenues increased due to higher pricing on natural gas at Tupper Montney and additional new well production volumes, partially offset by higher royalty rates.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. “Sales of purchased natural gas” is included in “Total revenues and other income” and “Cost of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 25.

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 March 31, 2025, lease operating expenses decreased by $29.2 million and transportation, gathering and processing expenses decreased by $7.6 million compared to the same period in 2024. Lower lease operating expenses in the Gulf of America were largely driven by lower sales volumes. Operating expenses at Canada Offshore decreased by $9.02 per barrel due to lower production and higher restart costs in the first quarter of 2024 associated the non-operated Terra Nova field. Lower transportation, gathering and processing expenses during the quarter were a result of overall lower production volumes in the Gulf of America.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization (DD&A) expense by geographic area were as follows:

DD&A expense for the three months ended March 31, 2025 decreased by $16.5 million compared to the same period in 2024. The decrease is primarily due to lower sales volumes in the Gulf of America and at Eagle Ford Shale and lower rates at Canada Offshore resulting from ARO adjustments, partially offset by higher sales volumes in Canada Offshore and higher rates in the Gulf of America resulting from increased drilling, completions and facilities developments costs.

Impairment of Assets

For the three months ended March 31, 2025, there were no impairments.

Impairment of assets for the three months ended March 31, 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 March 31, 2025 decreased by $29.9 million compared to the same period in 2024. In 2024, there were dry holes and previously suspended exploration costs relating to the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) exploration well and additional costs related to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

Income Taxes

Income taxes for the three months ended March 31, 2025 increased by $1.9 million compared to the same period in 2024. Higher income taxes were primarily the result of higher taxes in foreign jurisdictions, partially offset by lower year-to-date pretax 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 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 $48.2 million for the three months ended March 31, 2025, an unfavorable variance of $20.7 million compared to the same period of 2024. The unfavorable variance was primarily due to lower unrealized foreign exchange gains ($10.2 million) and unrealized losses on derivative instruments ($8.9 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 three months ended March 31, 2025 was $98.1 million lower compared to the same period in 2024. The decrease in cash flows from operations activities was primarily attributable to lower revenue from production ($121.9 million), partially offset by lower lease operating expenses ($29.2 million).

Cash Required by Investing Activities

Net cash required by investing activities for the three months ended March 31, 2025 was $120.7 million higher compared to the same period in 2024. The increase was primarily due to higher property additions and dry hole costs ($119.3 million), which included a gross payment of $100.0 million for the purchase of a FPSO in the 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 three months ended March 31, 2025 compared to the same period of 2024 was primarily attributable to higher field development costs in the Gulf of America, including the purchase of a

FPSO, increased exploratory drilling in Vietnam, and higher development drilling at Eagle Ford Shale. The purchased FPSO in the Gulf of America will remain at its current location, and continue supporting operations at the Cascade and Chinook fields.

Capital expenditures in 2025 primarily relate to development drilling and field development activities at Eagle Ford Shale ($92.7 million), the Gulf of America ($214.8 million), Tupper Montney and Kaybob Duvernay ($50.2 million), and the non-operated Hibernia field ($4.6 million) in Canada. Other international field development activities were largely in Vietnam ($18.6 million). Exploration costs in 2025 were $39.1 million, primarily comprised of activities in Vietnam for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells and activities in the Gulf of America related to long lead equipment purchases for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2025 increased by $182.4 million compared to the same period in 2024. In 2025, the cash provided by financing activities was due to net borrowings on the senior unsecured RCF ($200.0 million), partially offset by the repurchase of common shares ($100.1 million), cash dividends to shareholders of $0.33 per share ($47.0 million), withholding tax on stock-based incentive awards ($7.7 million), and distributions to the noncontrolling interest in MP GOM ($7.0 million). In 2024, cash required by financing activities was for the repurchase of common shares ($50.0 million), cash dividends to shareholders ($45.8 million), withholding tax on stock-based incentive awards ($25.3 million), and distributions to the noncontrolling interest in MP GOM ($23.0 million).

Liquidity

At March 31, 2025, the Company had approximately $1.5 billion of liquidity consisting of $392.9 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 March 31, 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 March 31, 2025, the interest rate in effect on borrowings under the RCF was 6.67%. At March 31, 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 March 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $83.1 million, the majority of which was held in Canada ($48.5 million), Vietnam ($9.0 million), and the U.K. ($7.8 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 March 31, 2025, net working capital decreased by $79.6 million compared to December 31, 2024. The decrease was primarily attributable to higher accounts payable ($66.1 million), lower cash balance ($30.7 million), and higher current asset retirement obligations ($29.4 million), partially offset by lower other accrued liabilities ($27.2 million) and higher inventory balances ($16.2 million). Higher accounts payable was primarily due to the timing of drilling and completions work and accruals relating to the purchase of the FPSO in the Gulf of America. Higher current asset retirement obligations were primarily attributable to planned abandonment activities in U.S. Offshore in the next 12 months. Lower other accrued liabilities were due to incentive payments and operating lease payments made in 2025. Inventory balances increased primarily due to timing of sales cargos at U.S. Offshore.

Capital Employed

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

At March 31, 2025, long-term debt of $1,474.8 million increased by $200.3 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 9.1 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $74.0 million in 2025, primarily due to shares repurchased ($100.9 million, including excise tax) and cash dividends paid ($47.0 million), partially offset by net income earned ($73.0 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 March 31, 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.

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 29, lower average crude oil and higher natural gas pricing during the first quarter of 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on May 5, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the table below:

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 second quarter of 2025, production is expected to average between 177.0 and 185.0 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

The Company’s capital expenditure spend for 2025 is 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. 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.

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.

On August 8, 2024, the Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available as of March 31, 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 RCF (see Note E).

Outlook (Continued)

As of May 5, 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.