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, 2026, increased $59.6 million compared to the same period in 2025. New wells in the Karnes and Catarina fields in the Eagle Ford Shale were the primary contributor to higher revenues for the period, contributing both higher volumes and realized prices. Canada also realized higher prices, but overall revenues were lower due to fewer cargoes offshore Canada compared to 2025. In the Gulf of America, both production and realized prices were lower compared to the first quarter of 2025. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

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, 2026, lease operating expenses decreased by $61.6 million, and transportation, gathering and processing expenses decreased by $1.8 million compared to the same period in 2025. Lower lease operating expenses are due to lower workover costs in the Gulf of America in the current quarter, particularly at the Samurai field. Further decreases in the Gulf of America are attributable to lower vessel rental costs as a result of the purchase of the Pioneer FPSO in 2025. Offshore Canada realized lower operating costs in the current quarter due to fewer cargoes in 2026 compared to 2025.

Depreciation, Depletion and Amortization Expenses

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

DD&A for the three months ended March 31, 2026 increased by $60.2 million. Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S. and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S. and offshore Canada.

Exploration Expenses

The Company’s exploration expenses were as follows:

Exploration expenses for the three months ended March 31, 2026 increased by $68.3 million compared to the same period in 2025. Higher exploration expenses in the current quarter were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons.

Income Taxes

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

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.

The Corporate segment reported a loss of $36.4 million for the three months ended March 31, 2026, a favorable variance of $11.8 million, compared to the same period in 2025. The favorable variance was primarily due to no losses on derivative instruments ($9.5 million) in the current quarter and higher foreign exchange gains ($8.8 million). These changes were partially offset by higher interest expense ($5.3 million) due to costs related to the redemption of the 2027 Notes and 2028 Notes.

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. 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. 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, 2026 was $20.5 million higher compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized prices and volumes resulting in higher revenue from production ($59.6 million) and lower lease operating expenses ($61.6 million), partially offset by the timing of net non-cash working capital ($85.2 million) and changes in other operating activities, net ($18.7 million), primarily due to fluctuations in foreign exchange rates ($8.9 million) and higher expenditures for asset retirements ($8.8 million).

Cash Required by Investing Activities

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

Financial Condition (Continued)

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, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory and development drilling in the Gulf of America, and higher development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower field development costs in the Gulf of America due to the prior year spend on the Pioneer FPSO purchase in the Gulf of America.

Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($105.8 million), Eagle Ford Shale ($98.9 million), Tupper Montney and Kaybob Duvernay ($54.8 million), and in Vietnam ($24.0 million). Exploration costs in 2026 were $178.1 million, primarily comprised of activities in Côte d'Ivoire related to exploration drilling for Bubale-1X (Block CI-709), Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells. Exploration costs were also driven by activities in the Gulf of America including lease acquisitions and exploration drilling at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Vietnam for the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 exploration well.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2026 increased by $52.7 million compared to the same period in 2025.

In 2026, the cash provided by financing activities was principally from a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million. The bond issuance was partially offset by the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), cash dividends to shareholders of $0.350 per share ($50.2 million), and $20.0 million in debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance.

In 2025, net cash provided by financing activities was from 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 ($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).

Financial Condition (Continued)

Liquidity

At March 31, 2026, the Company had approximately $2.4 billion of liquidity consisting of $378.8 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured Amended RCF with a major banking consortium.

The Company’s $2.0 billion senior unsecured Amended RCF expires in January 2031. As of March 31, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%. At March 31, 2026, the Company was in compliance with all covenants related to the Amended RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of March 31, 2026, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $94.6 million, the majority of which was held in Canada ($35.2 million), Côte d'Ivoire ($24.8 million), Vietnam ($10.5 million), Mexico ($7.9 million), Brunei ($6.9 million), and the U.K. ($6.3 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, 2026, net working capital increased by $48.8 million compared to December 31, 2025. The increase was primarily attributable to higher accounts receivable ($120.5 million) and lower current operating lease obligations ($8.6 million), partially offset by higher accounts payable ($73.6 million).

Higher accounts receivable and accounts payable were due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively. 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 Pioneer FPSO in the Gulf of America.

Capital Employed

A summary of capital employed at March 31, 2026 and December 31, 2025 follows.

At March 31, 2026, long-term debt of $1,548.1 million increased by $165.5 million compared to December 31, 2025, primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.9 years and a weighted average coupon of 6.2%.

Murphy shareholders’ equity decreased by $19.5 million in 2026, primarily due to dividends ($50.2 million), foreign currency translation ($23.7 million), partially offset by net income ($53.0 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, 2026, 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, 2025.

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.

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 three months ended March 31, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, 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 29, lower average crude oil and higher natural gas pricing during the first quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on May 4, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.

The regional conflict involving Iran has contributed to heightened geopolitical risk and significant volatility in global energy and shipping markets, primarily due to disruptions affecting transit through the Strait of Hormuz, which is a critical passage for oil, LNG, and other refined products. Although these developments have led to higher commodity prices, these developments have also led to increased transportation and insurance costs, and broader uncertainty across global supply chains, which may indirectly affect the Company through fluctuations in oil and gas prices, changes in demand, and higher operating or input costs. During the period, the Company has not experienced direct physical disruption to its operations, and the Company’s financial and operating results have been favorably impacted by price volatility. Looking forward, a prolonged or escalating conflict could further disrupt global energy flows, exacerbate price volatility, constrain access to markets or services, and adversely affect macroeconomic conditions, which could materially impact the Company’s future operating results, cash flows, and financial position.

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 tariff announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

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 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 March 31, 2026. The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA.

We cannot predict what impact economic factors (including, but not limited to, inflation, 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. Similarly, we cannot predict the impact that political instability or armed conflict in oil and natural gas producing regions, such as in Russia and Ukraine, the Middle East, and Venezuela, may have on pricing, global supply and demand for oil and gas. It is also uncertain how production quota decisions by OPEC and OPEC+, along with changes in membership, may influence pricing and the global supply–demand balance. 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 2026, production is expected to average between 161.0 and 169.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company’s capital expenditures for 2026 are expected to be between $1,200 million and $1,300 million, excluding noncontrolling interest. This range excludes noncontrolling interest of $53.0 million.

In the Gulf of America, Murphy will continue developing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter. In addition, the Company commenced drilling at the Chinook #8 (Walker Ridge 425) development well.

Outlook (Continued)

The Company commenced drilling on its third Côte d’Ivoire exploration well, Bubale-1X (Block CI-709), during the first quarter, with results expected in the second quarter.

The appraisal program at the Hai Su Vang (Golden Sea Lion) prospect in Vietnam is continuing on schedule following the successful completion of the Hai Su Vang-2X (Block 15-2/17) appraisal well in the first quarter. Also in the first quarter, the Company began drilling the Hai Su Vang-3X (Block 15-1/05) appraisal well. Hai Su Vang-3X is then expected to be followed by the Hai Su Vang-4X (Block 15-2/17) appraisal well.

Finally, Murphy 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, as well as changing commodity price environments, 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. 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. 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 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 March 31, 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 senior unsecured Amended RCF (see Note E).

As of May 4, 2026, 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.