What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-08-05 compared with 2026-05-06 · 601 added, 0 removed, 31 unchanged (95% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Overview (Continued)

exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

At June 30, 2026, the West Texas Intermediate (WTI) crude oil futures price was $68.96 per barrel, whereas the crude oil futures price at the end of July 2026 was $80.31, reflecting a 16% increase in price.

As of August 3, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $76.97 per barrel.

Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.

Results of Operations

Murphy’s Net income (loss) by type of business and geographic segment is presented below:

Income (Loss)

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Exploration and production

United States $ 274.2 $ 86.5 $ 430.9 $ 194.4

Canada 51.9 10.5 83.5 52.0

Other (30.2) (7.3) (112.8) (18.5)

Total exploration and production

295.9 89.7 401.6 227.9

Corporate and other (32.0) (55.9) (68.4) (104.1)

Income from continuing operations 263.9 33.8 333.2 123.8

Discontinued operations, net of tax 1

(0.4) 1.3 (1.0) 0.7

Net income including noncontrolling interest 263.5 35.1 332.2 124.5

Net income attributable to noncontrolling interest

31.3 12.8 47.0 29.2

Net income attributable to Murphy

$ 232.2 $ 22.3 $ 285.2 $ 95.3

1 The Company has presented its former U.K., Malaysia and U.S.

refining and marketing operations as discontinued operations in its consolidated financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Exploration and Production Continuing Operations

The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted.

The following is a summarized statement of operations for E&P continuing operations:

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Revenues and other income

Revenue from production

$ 926.3 $ 683.0 $ 1,658.7 $ 1,355.8

1.3 1.7 2.5 4.1

Total revenues and other income

927.6 684.7 1,661.2 1,359.9

Costs and expenses

Lease operating expenses 143.7 215.5 287.2 420.6

Severance and ad valorem taxes 15.0 10.8 28.7 19.5

Transportation, gathering and processing 45.3 54.0 92.3 102.9

Depreciation, depletion and amortization 259.7 257.6 511.7 449.4

Accretion of asset retirement obligations 14.8 14.4 29.2 28.5

Exploration expenses, including undeveloped lease amortization

39.3 10.4 122.1 24.9

Selling and general expenses 17.3 13.1 32.3 23.0

Other 17.6 1.6 23.8 6.3

Results of operations before taxes 374.9 107.3 533.9 284.8

Income tax provisions

79.0 17.6 132.3 56.9

Results of operations (excluding Corporate segment) 1

$ 295.9 $ 89.7 $ 401.6 $ 227.9

1 Includes results attributable to a noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

The following table contains the weighted average sales prices for the three and six months ended June 30, 2026 and 2025:

Three Months Ended

June 30, Six Months Ended

(Weighted average sales prices) 2026 2025 2026 2025

Crude oil and condensate – dollars per barrel

United States - Onshore

$ 99.55 $ 64.00 $ 86.18 $ 66.84

United States - Offshore 1

99.36 64.48 84.99 68.23

Canada - Onshore 2

84.08 59.94 77.28 61.73

Canada - Offshore 2

103.88 64.76 93.00 70.39

— 70.86 71.04 70.86

Natural gas liquids – dollars per barrel

United States - Onshore 23.08 19.56 20.55 21.07

United States - Offshore 1

21.66 19.35 18.97 22.75

Canada - Onshore 2

34.46 33.84 31.25 35.00

Natural gas – dollars per thousand cubic feet

United States - Onshore 2.41 2.75 3.07 3.03

United States - Offshore 1

3.38 3.47 4.55 3.89

Canada - Onshore 2

1.48 1.65 1.97 1.96

1 Prices include the effect of noncontrolling interest in MP GOM.

dollar equivalent.

The following table contains benchmark prices relevant to the Company for the three and six months ended June 30, 2026 and 2025:

Three Months Ended

June 30, Six Months Ended

(Average price for the period) 2026 2025 2026 2025

WTI ($/BBL) $ 92.79 $ 63.74 $ 82.36 $ 67.58

Henry Hub ($/MMBTU) 2.94 3.16 3.90 3.72

AECO (C$/MCF) 1.63 1.69 1.82 1.93

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Production Volumes

The following table contains hydrocarbons produced during the three and six months ended June 30, 2026 and 2025.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 32 .

Three Months Ended

June 30, Six Months Ended

(Barrels per day unless otherwise noted) 2026 2025 2026 2025

Net crude oil and condensate

United States - Onshore

26,853 28,519 27,670 22,779

United States - Offshore 1

50,920 58,840 51,377 57,222

Canada - Onshore

4,854 2,307 3,899 2,445

Canada - Offshore

7,880 5,638 8,440 7,237

Other 239 296 232 275

Total net crude oil and condensate

90,746 95,600 91,618 89,958

Net natural gas liquids

United States - Onshore

6,769 5,557 6,315 4,818

United States - Offshore 1

3,976 4,720 4,136 4,265

Canada - Onshore

570 494 549 516

Total net natural gas liquids

11,315 10,771 11,000 9,599

Net natural gas – thousands of cubic feet per day

United States - Onshore

32,861 32,389 32,971 29,306

United States - Offshore 1

49,178 52,964 50,160 52,062

Canada - Onshore

355,672 454,310 366,277 400,898

Total net natural gas

437,711 539,663 449,408 482,266

Total net hydrocarbons - including NCI 2,3

175,013 196,315 177,519 179,935

Noncontrolling interest

Net crude oil and condensate – barrels per day (5,481) (6,070) (5,382) (5,925)

Net natural gas liquids – barrels per day (195) (244) (210) (207)

Net natural gas – thousands of cubic feet per day (2,052) (1,942) (1,955) (1,590)

Total noncontrolling interest 2,3

(6,018) (6,638) (5,918) (6,397)

Total net hydrocarbons - excluding NCI 2,3

168,995 189,677 171,601 173,538

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Sales Volumes

The following table contains hydrocarbons sold during the three and six months ended June 30, 2026 and 2025.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 32 .

Three Months Ended

June 30, Six Months Ended

(Barrels per day unless otherwise noted) 2026 2025 2026 2025

Net crude oil and condensate

United States - Onshore

26,853 28,520 27,670 22,779

United States - Offshore 1

50,359 58,469 51,277 56,313

Canada - Onshore

4,854 2,307 3,899 2,444

Canada - Offshore

10,201 7,762 8,897 9,436

Other — 457 226 230

Total net crude oil and condensate

92,267 97,515 91,969 91,202

Net natural gas liquids

United States - Onshore

6,769 5,557 6,315 4,819

United States - Offshore 1

3,976 4,720 4,136 4,264

Canada - Onshore

570 494 549 516

Total net natural gas liquids

11,315 10,771 11,000 9,599

Net natural gas – thousands of cubic feet per day

United States - Onshore

32,861 32,388 32,971 29,306

United States - Offshore 1

49,178 52,964 50,160 52,062

Canada - Onshore

355,672 454,310 366,277 400,898

Total net natural gas

437,711 539,662 449,408 482,266

Total net hydrocarbons - including NCI 2,3

176,534 198,230 177,870 181,179

Noncontrolling interest

Net crude oil and condensate – barrels per day (5,396) (6,014) (5,365) (5,792)

Net natural gas liquids – barrels per day (195) (243) (210) (207)

Net natural gas – thousands of cubic feet per day (2,052) (1,942) (1,955) (1,590)

Total noncontrolling interest 2,3

(5,933) (6,581) (5,901) (6,264)

Total net hydrocarbons - excluding NCI 2,3

170,601 191,649 171,969 174,915

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

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:

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Revenues from production

United States - Oil

$ 698.6 $ 509.2 $ 1,220.4 $ 971.0

United States - Natural gas liquids

22.1 18.1 37.7 35.9

United States - Natural gas

22.3 24.8 59.6 52.7

133.5 58.3 204.3 147.5

Canada - Natural gas liquids

1.8 1.5 3.1 3.3

Canada - Natural gas

48.0 68.1 130.7 142.4

— 2.9 2.9 2.9

Total revenue from production

$ 926.3 $ 683.0 $ 1,658.7 $ 1,355.8

Revenue from production for the three months ended June 30, 2026 increased $243.3 million compared to the same period in 2025.

Higher revenues were primarily driven by higher realized crude oil prices in the U.S., partially offset by lower oil sales volumes in the Gulf of America due to decreased production at the Mormont, Kodiak, and Samurai fields related to planned and unplanned downtime.

Canada oil revenues increased, driven by higher oil prices and increased sales at Terra Nova and Hibernia, as well as new wells at Kaybob.

These items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper.

Revenues from production for the six months ended June 30, 2026 increased $302.9 million compared to the same period in 2025.

Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the U.S.

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 also increased, primarily driven by higher prices, as well as higher production at Kaybob from new wells.

These items were partially offset by lower Canada natural gas revenues, primarily due to lower production at Tupper due to the natural decline of new wells.

natural gas revenues increased from higher realized prices, while U.S.

NGL revenues increased primarily from higher volumes in the Eagle Ford Shale.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

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:

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars)

(Dollars per equivalent barrel)

2026 2025 2026 2025 2026 2025 2026 2025

Lease operating expenses

United States - Onshore

$ 34.2 $ 29.5 $ 9.60 $ 8.20 $ 66.6 $ 59.2 $ 9.31 $ 10.08

United States - Offshore

59.3 137.0 10.43 20.91 124.7 264.9 10.80 21.13

Canada - Onshore

32.5 35.6 5.52 4.98 65.4 65.8 5.53 5.21

Canada - Offshore

17.5 12.6 18.84 17.86 29.4 29.5 18.24 17.29

Other 0.2 0.8 — 19.95 1.1 1.2 25.74 29.02

Total lease operating expenses

$ 143.7 $ 215.5 $ 8.95 $ 11.95 $ 287.2 $ 420.6 $ 8.92 $ 12.83

Transportation, gathering and processing

United States - Onshore

$ 3.7 $ 2.1 $ 1.03 $ 0.62 $ 6.4 $ 4.5 $ 0.90 $ 0.77

United States - Offshore

20.8 28.1 3.66 4.28 43.3 54.5 3.75 4.35

Canada - Onshore

18.9 22.0 3.21 3.08 39.4 40.3 3.32 3.19

Canada - Offshore

1.9 1.8 2.01 2.53 3.2 3.6 2.01 2.10

Total transportation, gathering and processing

$ 45.3 $ 54.0 $ 2.82 $ 3.00 $ 92.3 $ 102.9 $ 2.87 $ 3.14

For the three months ended June 30, 2026 lease operating expenses decreased by $71.8 million and transportation, gathering and processing expenses decreased by $8.7 million compared to the same period in 2025.

Lower expenses were primarily driven by decreased costs in the Gulf of America, where workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Khaleesi, Marmalard, and Samurai, a one-time access fee received at Lucius, and 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.

Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes in the Gulf of America.

For the six months ended June 30, 2026 lease operating expenses decreased by $133.4 million, and transportation, gathering and processing expenses decreased by $10.6 million compared to the same period in 2025.

Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America.

Workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Samurai, Marmalard, and Khaleesi.

In addition, 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, contributed to the decrease in operating expenses.

Canada Offshore expenses decreased due to lower production-related costs at Terra Nova.

These items were partially offset by higher U.S.

Onshore costs from increased operated well counts in the Eagle Ford Shale.

Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes across multiple Gulf of America fields including Mormont, St.

Malo, and Khaleesi.

Canada Onshore transportation costs decreased due to lower volumes and ongoing mitigation efforts at Tupper.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Depreciation, Depletion and Amortization Expenses

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

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars)

(Dollars per equivalent barrel)

2026 2025 2026 2025 2026 2025 2026 2025

United States - Onshore

$ 113.9 $ 107.4 $ 32.01 $ 29.88 $ 227.2 $ 174.4 $ 31.79 $ 29.68

United States - Offshore

106.6 110.9 18.74 16.93 210.2 203.2 18.21 16.21

Canada - Onshore

29.2 30.0 4.96 4.20 55.6 54.1 4.69 4.29

Canada - Offshore

9.9 8.1 10.65 11.47 17.5 16.4 10.89 9.59

Other 0.1 1.2 — 28.38 1.2 1.3 27.84 31.02

$ 259.7 $ 257.6 $ 16.16 $ 14.28 $ 511.7 $ 449.4 $ 15.89 $ 13.70

DD&A for the three months ended June 30, 2026 increased by $2.1 million compared to the same period in 2025.

Higher DD&A was primarily driven by higher rates in the Eagle Ford Shale and the Gulf of America, as well as higher sales volumes at Canada Offshore from increased cargo deliveries at Terra Nova and Hibernia and higher volumes at Kaybob from new wells.

These items were partially offset by lower volumes in the Gulf of America related to planned and unplanned downtime at multiple fields and lower sales volumes at Tupper.

DD&A for the six months ended June 30, 2026 increased by $62.3 million compared to the same period in 2025.

Higher DD&A was primarily driven by significantly higher sales volumes in the Eagle Ford Shale from new Alice May wells at Karnes and new wells at Catarina, combined with higher rates in the Eagle Ford Shale and the Gulf of America.

Additionally, higher sales volumes at Kaybob from new wells contributed to the increase.

These items were partially offset by lower sales volumes in the Gulf of America and at Tupper.

Exploration Expenses

The Company’s exploration expenses were as follows:

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Exploration expenses

Dry holes and previously suspended exploration costs $ 13.5 $ (0.9) $ 80.6 $ (0.7)

Geological and geophysical 11.2 0.8 12.8 4.4

Other exploration 12.2 8.2 24.0 17.3

Undeveloped lease amortization 2.4 2.3 4.7 3.9

Total exploration expenses, including undeveloped lease amortization

$ 39.3 $ 10.4 $ 122.1 $ 24.9

Exploration expenses for the three months ended June 30, 2026 increased by $28.9 million compared to the same period in 2025.

Higher exploration expenses in the current quarter were largely due to exploration activities in Côte d’Ivoire, Vietnam, and the Gulf of America.

Dry holes and previously suspended exploration costs primarily related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam.

Exploration expenses for the six months ended June 30, 2026 increased by $97.2 million compared to the same period in 2025.

Higher exploration expenses in the current period 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, and the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam, all of which encountered non-commercial hydrocarbons.

Exploration activities in the Gulf of America also contributed to the higher exploration costs.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Other expenses increased by $16.0 million and $17.5 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in a joint venture dispute settlement provision.

Income taxes for the three and six months ended June 30, 2026 increased by $61.4 million and $75.4 million, respectively, compared to the same periods 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 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 $32.0 million for the three months ended June 30, 2026 a favorable variance of $23.9 million compared to the same period in 2025.

The favorable variance was primarily due to higher foreign exchange gains ($44.0 million), driven by favorable currency movements in Canada.

These gains were partially offset by no repeat of gains on derivative instruments in 2026 ($10.3 million) and lower income tax benefit ($14.5 million) due to higher current period net income.

The Corporate segment reported a loss of $68.4 million for the six months ended June 30, 2026 a favorable variance of $35.7 million, compared to the same period in 2025.

The favorable variance was primarily due to higher foreign exchange gains ($52.9 million).

These favorable items were partially offset by higher income tax expense ($17.8 million), and higher interest expense ($5.2 million) related to costs associated with 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

The following table presents the Company’s cash flows for the periods presented:

Six Months Ended

(Millions of dollars)

Net cash provided (required) by:

Net cash provided by continuing operations activities $ 977.1 $ 658.7

Net cash required by investing activities

(889.7) (679.4)

Net cash provided (required) by financing activities 19.0 (22.4)

Effect of exchange rate changes on cash and cash equivalents 0.3 (0.9)

Net increase (decrease) in cash and cash equivalents $ 106.7 $ (43.9)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the six months ended June 30, 2026 increased by $318.4 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 a $302.9 million increase in revenue from production, and lower lease operating expenses ($133.4 million).

These favorable impacts were partially offset by a $65.1 million decrease in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations, as well as a $48.4 million unfavorable change in net non-cash working capital, which was also affected by higher commodity prices.

Cash Required by Investing Activities

Net cash required by investing activities for the six months ended June 30, 2026 was $210.2 million higher compared to the same period in 2025.

The increase was primarily due to higher property additions and dry hole costs ($188.1 million) and higher acquisition capital ($22.1 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.

Six Months Ended

(Millions of dollars) 2026 2025

Property additions and dry hole costs $ 866.2 $ 678.0

Acquisition of oil and natural gas properties 23.5 1.4

Geophysical and other exploration expenses 34.3 19.3

Capital expenditure accrual changes and other 54.2 (20.3)

Total capital expenditures $ 978.2 $ 678.4

Total accrual basis capital expenditures are shown below.

Six Months Ended

(Millions of dollars) 2026 2025

Capital Expenditures

Exploration and production $ 961.9 $ 671.4

Corporate 16.3 7.0

Total capital expenditures $ 978.2 $ 678.4

Higher capital expenditures in the six months ended June 30, 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 spending in Vietnam, which included progressing the LDV-A platform construction and pipe-laying campaign.

These increases were partially offset by lower field

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

development costs in the Gulf of America due to the prior year purchase of the Pioneer FPSO in the Gulf of America.

Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($278.7 million), the Eagle Ford Shale ($187.4 million), the Tupper Montney and the Kaybob Duvernay ($112.8 million), and in Vietnam ($55.0 million).

Exploration costs in 2026 were $314.3 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, and the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05).

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.

Cash Provided (Required) by Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2026 increased by $41.4 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), year-to-date cash dividends to shareholders of $0.70 per share ($100.3 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.1 million), and distributions to the noncontrolling interest in MP GOM ($21.2 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 $0.65 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).

At June 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $483.9 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 June 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 June 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 5.90%.

At June 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 June 30, 2026 cash and cash equivalents held outside the U.S.

included U.S.

dollar equivalents of approximately $160.2 million, the majority of which was held in Canada ($89.4 million), Côte d'Ivoire ($34.6 million), Vietnam ($12.7 million), Mexico ($7.9 million), Brunei ($6.1 million), and the U.K.

($4.6 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

Working Capital

(Millions of dollars) June 30, 2026 December 31, 2025

Working capital

Total current assets $ 1,026.8 $ 816.7

Total current liabilities 1,202.3 1,062.7

Net working capital liability

$ (175.5) $ (246.0)

As of June 30, 2026 net working capital increased by $70.5 million compared to December 31, 2025.

The increase was primarily attributable to a higher cash balance at the end of the period ($106.7 million) and higher accounts receivable ($96.4 million), partially offset by higher accounts payable ($99.1 million), higher current asset retirement obligations ($17.3 million), and higher income taxes payable ($14.1 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.

Higher current asset retirement obligations were due to reclassification of certain obligations from long-term to current for anticipated well abandonment activities expected within the next 12 months.

Higher income taxes were due to higher pretax net income.

Capital Employed

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

June 30, 2026 December 31, 2025

(Millions of dollars) Amount % Amount %

Capital employed

Long-term debt $ 1,547.9 22.7 % $ 1,382.6 21.3 %

Murphy shareholders' equity 5,259.0 77.3 % 5,118.4 78.7 %

Total capital employed $ 6,806.9 100.0 % $ 6,501.0 100.0 %

At June 30, 2026, long-term debt of $1,547.9 million increased by $165.3 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 8.7 years and a weighted average coupon of 6.3%.

Murphy shareholders’ equity increased by $140.6 million in 2026, primarily due to net income ($285.2 million) and ($15.5 million) stock award amortization, partially offset by dividends ($100.3 million) and foreign currency translation ($54.6 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 June 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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.

Three Months Ended

June 30, Six Months Ended

(Millions of dollars, except per share amounts)

2026 2025 2026 2025

Net income attributable to Murphy (GAAP) 1

$ 232.2 $ 22.3 $ 285.2 $ 95.3

Discontinued operations (income) loss 0.4 (1.3) 1.0 (0.7)

Net income from continuing operations attributable to Murphy 232.6 21.0 286.2 94.6

Foreign exchange (gain) loss (9.2) 34.3 (18.6) 34.3

Unrealized gain on derivative instruments — (10.3) — (1.4)

Total adjustments, before taxes (9.2) 24.0 (18.6) 32.9

Income tax (benefit) expense related to adjustments

2.4 (6.5) 4.8 (8.3)

Total adjustments, after taxes (6.8) 17.5 (13.8) 24.6

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 225.8 $ 38.5 $ 272.4 $ 119.2

Net income from continuing operations per average diluted share (GAAP)

$ 1.59 $ 0.15 $ 1.96 $ 0.66

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 1.55 $ 0.27 $ 1.87 $ 0.83

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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.

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Net income attributable to Murphy (GAAP) 1

$ 232.2 $ 22.3 $ 285.2 $ 95.3

Income tax expense 77.0 1.1 127.0 33.8

Interest expense, net 24.9 25.1 53.9 48.6

Depreciation, depletion and amortization expense 1

254.0 250.8 500.8 438.2

EBITDA attributable to Murphy (Non-GAAP) 1

$ 588.1 $ 299.3 $ 966.9 $ 615.9

Exploration expenses 1

39.3 10.3 122.1 24.8

EBITDAX attributable to Murphy (Non-GAAP) 1

$ 627.4 $ 309.6 $ 1,089.0 $ 640.7

EBITDA attributable to Murphy (Non-GAAP) 1

$ 588.1 $ 299.3 $ 966.9 $ 615.9

Foreign exchange (gain) loss (9.2) 34.3 (18.6) 34.3

Accretion of asset retirement obligations 1

13.4 12.9 26.3 25.4

Unrealized gain on derivative instruments — (10.3) — (1.4)

Discontinued operations (income) loss 0.4 (1.3) 1.0 (0.7)

Adjusted EBITDA attributable to Murphy (Non-GAAP) 1

$ 592.7 $ 334.9 $ 975.6 $ 673.5

Exploration expenses 1

39.3 10.3 122.1 24.8

Adjusted EBITDAX attributable to Murphy

$ 632.0 $ 345.2 $ 1,097.7 $ 698.3

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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.

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2026 2025 2026 2025

Net cash provided by continuing operations activities (GAAP) $ 655.9 $ 358.1 $ 977.1 $ 658.7

increase (decrease) in non-cash working capital (67.5) (30.7) 40.5 (7.9)

Operating cash flow excluding working capital adjustments (Non-GAAP)

588.4 327.4 1,017.6 650.8

property additions and dry hole costs 1

(478.4) (309.6) (866.2) (678.0)

Free cash flow (Non-GAAP) $ 110.0 $ 17.8 $ 151.4 $ (27.2)

Cash dividends paid (50.1) (46.4) (100.3) (93.4)

Distributions to noncontrolling interest (21.2) (11.2) (21.2) (18.2)

Debt costs (0.1) — (22.5) —

Withholding tax on stock-based incentive awards — — (7.8) (7.7)

Acquisition of oil and natural gas properties (0.8) — (23.5) (1.4)

Adjusted free cash flow (Non-GAAP) $ 37.8 $ (39.8) $ (23.9) $ (147.9)

1 Property additions for the six months ended June 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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 32 , higher average crude oil and lower natural gas pricing during the second quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on August 3, 2026 forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.

WTI ($/BBL) 76.97 69.99

NYMEX ($/MMBTU) 3.09 3.38

AECO (US$ Equivalent/MCF) 1.35 1.69

The regional conflict involving Iran continues to contribute 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.

In July 2026, the Trump Administration imposed a 10% or 12.5% tariff on 60 trading partners pursuant to Section 301 of the Trade Act of 1974.

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.

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 third quarter of 2026, production is expected to average between 171.0 and 179.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company now expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million, compared with its prior guidance of $1,200 million to $1,300 million provided in the first quarter.

This increase is driven primarily by additional capital related to the Bubale-1X (Block CI-709) discovery and the Bubale West-1X (Block CI-103) appraisal well, incremental Eagle Ford Shale activity, and higher-than-anticipated costs associated with Chinook #8 (Walker Ridge 425) drilling.

Noncontrolling interest capital expenditures are expected to be $65 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 of 2026.

The Company currently expects these wells to begin production in the fourth quarter of 2027.

In addition, the Company has initiated completion activities at the Chinook #8 (Walker Ridge 425) well, and expects the well to come online in the fourth quarter of 2026.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Outlook (Continued)

In Côte d’Ivoire, the Company drilled a successful exploration well at Bubale-1X (Block CI-709), and in July 2026 spud its first appraisal well, the Bubale West-1X (Block CI-103).

The appraisal program is expected to include up to five wells over the next 18 to 24 months.

The Hai Su Vang (Golden Sea Lion) appraisal program in Vietnam has been completed following the completion of the Hai Su Vang-2X (Block 15-2/17) and Hai Su Vang-3X (Block 15-1/05) appraisal wells, which encountered hydrocarbons, and the Hai Su Vang-4X (Block 15-2/17) appraisal well, which did not and was expensed as a dry hole.

The Company is evaluating development alternatives and progressing post-appraisal studies, with a final investment decision currently anticipated in the fourth quarter of 2027.

In addition, in July the Company spud the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well.

Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with first oil anticipated in the fourth quarter of 2026.

In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally.

During the second quarter, Murphy progressed key agreements for offshore exploration blocks in Cameroon and submitted an application for offshore blocks in Mauritania, initiating discussions with the government.

The Company anticipates finalizing the contracts in both countries in the second half 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 June 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 Amended RCF (see Note E ).

As of August 3, 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:

(MMCF/d) Price/MCF Remaining Period

Area Commodity Type 1

Start Date End Date

Canada Natural Gas Fixed price forward sales 88 C$2.81 7/1/2026 9/30/2026

Canada Natural Gas Fixed price forward sales 59 C$3.00 10/1/2026 12/31/2026

Canada Natural Gas Fixed price forward sales 9.5 C$3.14 1/1/2027 12/31/2027

1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Forward-Looking Statements

29 unchanged sentences

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What changed 10-Q

Item 2. Management’s Discussion and Analysis