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:

Revenue from production for the three months ended September 30, 2026 increased $128.2 million compared to the same period in 2025. The increase was primarily driven by higher realized oil prices in the U.S. and Canada. In Canada, higher volumes at Terra Nova and Kaybob further increased revenues, while higher natural gas prices at Tupper Montney offset lower sales volumes. These favorable impacts were partially offset by lower volumes in the Eagle Ford Shale due to fewer new wells online in the period, and in the Gulf of America due to the natural decline of wells.

Revenues from production for the nine months ended September 30, 2026 increased $431.1 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized oil prices across the U.S. and Canada. The Eagle Ford Shale had higher oil volumes from new wells, while higher volumes at Kaybob and Terra Nova further increased revenues. At Tupper Montney, higher natural gas prices offset lower volumes. These favorable impacts were partially offset by lower Gulf of America oil volumes, particularly at Mormont and Khaleesi due to natural decline.

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, 2026 lease operating expenses decreased by $35.2 million and transportation, gathering and processing expenses decreased by $1.0 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by lower Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and the non-recurrence of prior-year workover costs at Marmalard and Khaleesi. These decreases were partially offset by current-quarter workover costs at Mormont.

For the nine months ended September 30, 2026 lease operating expenses decreased by $168.6 million, and transportation, gathering and processing expenses decreased by $11.7 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by favorable Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and lower workover costs at Samurai and Khaleesi. In addition, lower FPSO rental fees at Cascade & Chinook also decreased lease operating expenses. The Company also received a one-time access fee related to the Lucius field, which further contributed to decreases during the period. These decreases were partially offset by higher Eagle Ford Shale operating costs related to workover costs and increased number of wells.

Lower transportation, gathering and processing expenses were primarily due to lower sales volumes in the Gulf of America.

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, 2026 decreased by $12.6 million compared to the same period in 2025. The decrease was primarily driven by lower volumes in the Eagle Ford Shale due to fewer new wells online in the quarter, as well as lower production in the Gulf of America due to the natural decline of wells.

DD&A for the nine months ended September 30, 2026 increased by $49.8 million compared to the same period in 2025. The increase was primarily driven by higher volumes and depletion rates in the Eagle Ford Shale and higher depletion rates in the Gulf of America. These increases were partially offset by lower volumes in the Gulf of America.

Exploration Expenses

The Company’s exploration expenses were as follows:

Exploration expenses for the three months ended September 30, 2026 increased by $0.6 million compared to the same period in 2025. Higher dry hole costs related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) were offset by lower geological and geophysical activity in the Gulf of America.

Exploration expenses for the nine months ended September 30, 2026 increased by $97.8 million compared to the same period in 2025. Higher exploration expenses in the current period were primarily driven by dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam, all of which encountered non-commercial hydrocarbons.

Selling and General Expenses

Selling and general expenses increased $8.3 million and $17.6 million for the three and nine months ended September 30, 2026, respectively, compared with the same periods in 2025. Increases were primarily due to higher compensation costs, incentive awards and professional fees.

Other

Other expenses increased $23.4 million for the three months ended September 30, 2026 compared with the same period in 2025, primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney and additional abandonment costs in the Gulf of America.

Other expenses increased $40.8 million for the nine months ended September 30, 2026 compared with the same period in 2025 primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney, combined with the settlement of a joint venture dispute and additional abandonment costs in the Gulf of America.

Income Taxes

Income taxes for the three and nine months ended September 30, 2026 increased by $42.8 million and $118.3 million, respectively, compared to the same periods in 2025. Higher income tax expenses were primarily due to higher pretax income in the United States and Canada. The tax impact was also affected by exploration expenses incurred in foreign jurisdictions where no income tax benefits are currently available. The Company also recognized an income tax deduction for prior years’ Australia exploration spend.

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 $31.5 million for the three months ended September 30, 2026, an unfavorable variance of $12.9 million compared to the same period in 2025. The unfavorable variance was primarily due to lower foreign exchange gains ($11.3 million) and the non-repeat of prior year derivative gains ($5.7 million), partially offset by a higher income tax benefit ($7.7 million).

The Corporate segment reported a loss of $99.9 million for the nine months ended September 30, 2026, a favorable variance of $22.8 million compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($41.5 million) and was partially offset by higher net interest expense associated with the 2034 Notes and a lower income tax benefit ($10.1 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 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 nine months ended September 30, 2026 increased by $519.4 million compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized commodity prices, which resulted in an increase in revenue from production ($431.1 million), and lower lease operating expenses ($168.6 million), primarily driven by lower workover expenses in the Gulf of America. These favorable impacts were partially offset by a $51.3 million increase in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations.

Cash Required by Investing Activities

Net cash required by investing activities for the nine months ended September 30, 2026 was $510.3 million higher compared to the same period in 2025. The increase was primarily due to higher property additions and dry hole costs ($506.0 million).

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, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory spending and development drilling in the Gulf of America and in Vietnam. These increases were partially offset by lower development spending in the Eagle Ford Shale and the prior year purchase of the Pioneer FPSO vessel in the Gulf of America.

Development capital expenditures in 2026 primarily related to development drilling and field development activities in the Gulf of America ($447.8 million), the Eagle Ford Shale ($232.2 million), the Tupper Montney and the Kaybob Duvernay ($128.1 million), and in Vietnam ($99.4 million).

Exploration expenditures in 2026 were $471.0 million, primarily comprised of activities in Côte d’Ivoire related to exploration drilling for the Bubale exploration and appraisal program (Blocks CI-709 and CI-103), and the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells. Exploration spending was also driven by activities in the Gulf of America, including federal lease acquisitions and exploration drilling at the Cello #1 and Banjo #1 exploration wells (Mississippi Canyon 385), and in Vietnam, including the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05) and the Lac Da Trang (White Camel) North (Block 15-1/05) exploration well.

Cash Required by Financing Activities

Net cash required by financing activities for the nine months ended September 30, 2026 decreased by $111.0 million compared to the same period in 2025.

In 2026, net cash required by financing activities was principally from 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), year-to-date cash dividends to shareholders of $1.05 per share ($150.5 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.5 million), and distributions to the noncontrolling interest in MP GOM ($21.2 million). These amounts were partially offset by a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million.

In 2025, net 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 guaranteed RCF ($150.0 million).

Liquidity

At September 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $500.3 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured guaranteed Amended RCF with a major banking consortium.

The Company’s $2.0 billion Amended RCF expires in January 2031. As of September 30, 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 September 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 6.16%. At September 30, 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 September 30, 2026 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $105.1 million, the majority of which was held in Canada ($60.1 million), Côte d'Ivoire ($11.9 million), Vietnam ($9.5 million), Mexico ($7.7 million), Brunei ($5.4 million), and the U.K. ($4.4 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, 2026 net working capital increased by $188.8 million compared to December 31, 2025. The increase was primarily attributable to a higher cash balance at the end of the period ($123.1 million) and higher accounts receivable ($112.5 million), partially offset by higher accounts payable ($50.6 million).

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

Capital Employed

A summary of capital employed at September 30, 2026 and December 31, 2025 follows.

At September 30, 2026, long-term debt of $1,623.1 million increased by $240.5 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 8.4 years and a weighted average coupon of 6.3%. In addition, during the quarter, the Company commenced a finance lease for a FSO supporting operations at the Lac Da Vang field in Vietnam, resulting in a $75.3 million increase in long-term debt.

Murphy shareholders’ equity increased by $266.5 million in 2026, primarily due to net income ($456.3 million) and ($24.1 million) stock award amortization, partially offset by dividends ($150.5 million) and foreign currency translation ($59.0 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 September 30, 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 nine months ended September 30, 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 36, higher average crude oil and natural gas pricing during the third quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on November 2, 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 continues to contribute to heightened geopolitical risk and volatility in global energy markets, including disruptions and security risks affecting transit through the Strait of Hormuz. The Company has not experienced any direct physical disruption to its operations as a result of the conflict. However, the conflict may indirectly affect the Company through fluctuations in oil and natural gas prices and demand, increased costs or reduced availability of equipment and services, and broader supply chain pressures. A prolonged or escalating conflict, including further disruptions to critical energy infrastructure or maritime routes, could increase market volatility and adversely affect economic conditions, which could affect the Company’s future operating results, cash flows and financial position.

Changes in tariffs and trade policies may affect the cost and availability of goods and services used in E&P operations or contribute to inflation in the countries in which the Company operates. In July 2026, the Trump Administration implemented tariffs of generally 10% or 12.5% on imports from 60 economies pursuant to Section 301 of the Trade Act of 1974. The Company continues to monitor the actual and potential effects of these tariffs, other trade restrictions and related governmental actions, as well as opportunities to mitigate their impacts. The ultimate effects of these measures on the Company’s supply chain, capital expenditures and operating costs remain uncertain.

The Company cannot predict the impact economic conditions, including inflation, trade policies, tariffs, other trade restrictions and a possible economic recession, may have on future commodity prices or the cost and availability of goods and services used in E&P operations. Similarly, the Company cannot predict the effects of political instability, armed conflict, sanctions, changes in sanctions policy or other governmental actions affecting oil- and natural-gas-producing regions, including Russia and Ukraine, the Middle East and Venezuela. Such developments may affect global oil and natural gas supply, demand and pricing. It is also uncertain how production decisions by OPEC and participating non-OPEC countries, compliance with production targets and changes in participation or production capacity may influence commodity prices and the global supply-demand balance. Lower commodity prices or higher costs, should they occur, would reduce earnings and operating cash flows and could result in material future impairment charges.

For the fourth quarter of 2026, production is expected to average between 174.0 and 182.0 thousand barrels of oil equivalent per day, excluding noncontrolling interest. The Company now also expects full-year 2026 production, excluding noncontrolling interest, to be between 176.0 and 178.0 thousand barrels of oil equivalent per day, compared with its prior guidance of 167.0 to 175.0 thousand barrels of oil equivalent per day. The increased guidance is primarily attributable to accelerated Eagle Ford Shale activity, new well outperformance and lower royalties at Tupper Montney.

The Company expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million.

In the Gulf of America, the Chinook #8 (Walker Ridge 425) well commenced production during the quarter. Murphy will also continue progressing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter of 2026. The Company currently expects these wells to begin production in the fourth quarter of 2027. Finally, the evaluation of multiple blocks acquired in federal lease sales is ongoing.

Outlook (Continued)

In Côte d’Ivoire, the Company drilled a successful appraisal well at Bubale West-1X (Block CI-103). Going forward, the Bubale appraisal program is expected to include two to four wells over the next 18 to 24 months.

The Company commenced production at Lac Da Vang (Golden Camel), Block 15-1/05 in Vietnam during the quarter, and also drilled a discovery at the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well. At Hai Su Vang (Golden Sea Lion), the Company is evaluating development alternatives and advancing post-appraisal studies, with a final investment decision currently anticipated in late 2027.

In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally. Subsequent to the third quarter, the Company signed agreements with the government of Mauritania for two offshore exploration blocks, and is working to finalize an agreement in Cameroon before year-end.

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 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, our planned exploration and appraisal program and our bond terms, 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 September 30, 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 guaranteed Amended RCF (see Note E).

As of November 2, 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.