Murphy Oil Corp: Form 10-Q for the period ended Jun 30, 2026

Overview (Continued)

lower production handling agreement costs at King’s Quay from lower volumes; these items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale. Higher other income was primarily due to foreign exchange gains driven by favorable currency movements in Canada. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, as well as certain exploration expenses that did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher exploration expenses were largely due to exploration activities in the Gulf of America and costs related to second-quarter appraisal programs in Vietnam and Côte d’Ivoire. Higher other operating expenses were related to the increase in a joint venture settlement provision.

For the three months ended June 30, 2026 total hydrocarbon production was 175,013 barrels of oil equivalent per day, a decrease of 11% compared to the second quarter of 2025. The decrease was principally due to lower offshore production in the Gulf of America, primarily attributable to planned and unplanned downtime at multiple fields, partially offset by higher production in Canada Offshore. Higher Canada Offshore production was driven by increased production at Terra Nova and Hibernia, while higher Canada Onshore production was driven by new wells at Kaybob. Higher Eagle Ford Shale production was primarily the result of new wells online in the current year.

Net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2026 was $333.2 million, an increase of $209.3 million compared to the same period of 2025. Higher net income from continuing operations was primarily driven by higher revenues from production ($302.9 million), lower lease operating expenses ($133.4 million), higher other income ($51.0 million), and lower transportation, gathering and processing expenses ($10.6 million). These favorable items were partially offset by higher exploration expenses ($97.2 million), higher income tax expense ($93.2 million), higher DD&A ($63.0 million), and higher other operating expenses ($11.7 million).

Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the United States contributing the majority of the increase from higher prices in the Gulf of America and both higher prices and volumes in the Eagle Ford Shale from new wells at Karnes and Catarina. Canada oil revenues increased from higher prices along with higher production at Kaybob from new wells; these items were partially offset by lower Canada natural gas revenues, primarily due to reduced production and sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Samurai, Marmalard and Khaleesi, lower production handling agreement costs at King’s Quay from lower volumes, and lower FPSO rental fees at Cascade & Chinook following the vessel purchase in early 2025. Higher other income was primarily due to favorable foreign exchange movements. Higher exploration expenses 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, and the Hai Su Vang-4X (Golden Sea Lion) Block 15-2/17 appraisal well in Vietnam, which did not encounter hydrocarbons and was also expensed as a dry hole. Exploration activities in the Gulf of America also contributed to the higher exploration costs. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, and certain exploration expenses did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher DD&A was primarily driven by higher sales volumes in the Eagle Ford Shale, combined with higher rates in the Eagle Ford Shale and the Gulf of America, and higher sales volumes at Kaybob from new wells; these items were partially offset by lower sales volumes in the Gulf of America and at Tupper. Higher other operating expenses were related to the increase in a joint venture settlement provision.

For the six months ended June 30, 2026, total hydrocarbon production was 177,519 barrels of oil equivalent per day, a decrease of 1% compared to the same period in 2025. The decrease was principally due to lower production in the Gulf of America, primarily from planned and unplanned downtime at multiple fields, and lower natural gas production at Tupper. These decreases were largely offset by higher production in the Eagle Ford Shale from new wells, higher Canada Offshore production from Terra Nova and Hibernia, and higher Canada Onshore production from new wells at Kaybob.

Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must

The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, foreign currency exchange rates, and interest rates. As described in Note L, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

Commodity Price Risk

There were no commodity-based derivative contracts in place as of June 30, 2026.

Foreign Exchange Risk

There were no derivative foreign exchange contracts in place at June 30, 2026.

Interest Rate Risk

The Company’s senior unsecured Amended RCF provides for variable interest rate borrowings. As of June 30, 2026 we had no outstanding borrowings under the Amended RCF, and therefore, no related exposure to interest rate risk.

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During the quarter ended June 30, 2026 there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in “Item 1A. Risk Factors” in the Company’s 2025 Form 10-K filed on February 25, 2026. The Company has not identified any additional risk factors not previously disclosed in its 2025 Form 10-K report.