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MURPHY OIL CORP (MUR)

CIK: 0000717423. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-25.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=717423. Latest filing source: 0001628280-26-011709.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue2,718,823,000USD20252026-02-25
Net income104,234,000USD20252026-02-25
Assets9,832,626,000USD20252026-02-25

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000717423.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric2016201720182019202020212022202320242025
Revenue1,811,238,0001,443,988,0001,791,401,0002,829,053,0001,967,341,0002,299,281,0003,932,662,0003,460,147,0003,028,474,0002,718,823,000
Net income-275,970,000-311,789,000411,094,0001,149,732,000-1,148,777,000-73,664,000965,047,000661,559,000407,171,000104,234,000
Operating income-388,903,000-26,319,000215,587,000445,293,000-1,362,309,000281,435,0001,586,710,0001,042,029,000602,593,000301,237,000
Diluted EPS-1.60-1.812.366.98-7.48-0.486.134.222.700.72
Assets10,295,860,0009,860,900,00011,052,600,00011,718,500,00010,620,900,00010,304,900,00010,309,000,0009,766,700,0009,667,479,0009,832,626,000
Liabilities5,854,945,0005,913,893,0006,226,705,0005,984,144,0005,160,059,0004,217,044,0004,325,636,0004,595,929,000
Stockholders' equity4,916,679,0004,620,191,0004,829,299,0005,467,460,0004,214,337,0004,157,311,0004,994,774,0005,362,794,0005,194,250,0005,118,380,000
Cash and cash equivalents872,797,000964,988,000359,923,000306,760,000310,606,000521,184,000491,963,000317,074,000423,569,000377,196,000
Net margin-15.24%-21.59%22.95%40.64%-58.39%-3.20%24.54%19.12%13.44%3.83%
Operating margin-21.47%-1.82%12.03%15.74%-69.25%12.24%40.35%30.12%19.90%11.08%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000717423.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2022-Q22022-06-302.23reported discrete quarter
2022-Q32022-09-303.36reported discrete quarter
2023-Q12023-03-311.22reported discrete quarter
2023-Q22023-06-30814,588,00098,286,0000.62reported discrete quarter
2023-Q32023-09-30959,645,000255,342,0001.63reported discrete quarter
2023-Q42023-12-31844,198,000116,286,000derived Q4 = FY annual - nine-month YTD
2024-Q12024-03-31796,412,00090,002,0000.59reported discrete quarter
2024-Q22024-06-30802,771,000127,739,0000.83reported discrete quarter
2024-Q32024-09-30758,331,000139,094,0000.93reported discrete quarter
2024-Q42024-12-31670,960,00050,336,000derived Q4 = FY annual - nine-month YTD
2025-Q12025-03-31665,711,00073,036,0000.50reported discrete quarter
2025-Q22025-06-30695,570,00022,280,0000.16reported discrete quarter
2025-Q32025-09-30732,985,000-2,973,000-0.02reported discrete quarter
2025-Q42025-12-31624,557,00011,891,000derived Q4 = FY annual - nine-month YTD
2026-Q12026-03-31733,552,00052,986,0000.37reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0001628280-26-031370.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

ITEM 2.  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

March 31,

(Millions of dollars)

2026

2025

Net cash provided by continuing operations activities (GAAP)

$

321.2 

$

300.7 

Exclude: increase in non-cash working capital

108.0 

22.8 

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

429.2 

323.5 

Less: property additions and dry hole costs 1

(387.8)

(368.4)

Free cash flow (Non-GAAP)

$

41.4 

$

(44.9)

Less: cash dividends paid

(50.2)

(47.0)

Less: distributions to noncontrolling interest

— 

(7.0)

Less: debt costs

(22.4)

— 

Less: withholding tax on stock-based incentive awards

(7.8)

(7.7)

Less: acquisition of oil and natural gas properties

(22.7)

(1.4)

Adjusted free cash flow (Non-GAAP)

$

(61.7)

$

(108.0)

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.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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.

2026

2027

WTI ($/BBL)

93.58

76.88

NYMEX ($/MMBTU)

3.39

3.64

AECO (US$ Equivalent/MCF)

1.37

1.79

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.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

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:

Volumes

(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type 1

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

78

C$2.94

4/1/2026

6/30/2026

Canada

Natural Gas

Fixed price forward sales

78

C$2.94

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.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and intent to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other environmental, social and governance matters, make capital expenditures, pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply and demand levels, actions t

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-25. Report date: 2025-12-31.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the consolidated financial statements and accompanying notes to consolidated financial statements, which are included in Item 8 of this Annual Report on Form 10-K. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section and “Risk Factors” under Item 1A. Discussion and analysis of 2023 results and year-over-year comparisons between 2024 and 2023 are not included in this Form 10-K and can be found in “Item 7” of the 2024 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.

Murphy Oil Corporation is a worldwide oil and natural gas E&P company with both onshore and offshore operations and properties. The Company produces oil and natural gas primarily in the U.S. and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide. A more detailed description of the Company’s significant assets can be found in “Item 1” of this Form 10-K report.

The analysis and discussion in this section includes amounts attributable to a noncontrolling interest (NCI) in MP GOM, unless otherwise noted.

Significant Company financial and operational highlights during 2025 were as follows:

•Generated net income of $138.8 million ($104.2 million excluding NCI) and net cash provided by operating activities of $1,247.8 million;

•Produced 189 thousand BOEPD (182 thousand BOEPD excluding NCI);

•Repurchased 3.6 million shares of common stock under the share repurchase program for $100.0 million ($100.8 million including excise taxes and fees) under the capital allocation plan1;

•Achieved 101% (103% excluding NCI) total proved reserve replacement with year-end proved reserves of 730.0 million MMBOE (715.0 MMBOE excluding NCI);

•Closed the strategic acquisition of the Pioneer floating production, storage and offloading vessel (FPSO) in the Gulf of America for a gross purchase price of $125.0 million; and

•Drilled oil discoveries at the Lac Da Hong-1X (Pink Camel), Block 15-1/05 and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells in Vietnam.

Subsequent to year end:

•Issued $500.0 million of 6.50% senior notes due in 2034 and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;

•Upsized senior unsecured revolving credit facility from $1.35 billion to $2.00 billion and extended maturity from 2029 to 2031;

•Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced a dry hole at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire; and

•Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.

1 Details of the capital allocation plan can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024. The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock.

32

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Murphy’s continuing operations generate revenue by producing oil and natural gas in the U.S. and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of oil and natural gas. In order to make a profit and generate cash in its E&P business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

For the year ended December 31, 2025, the Company’s net income from continuing operations was $138.3 million, a decrease of $351.0 million compared to 2024. Lower net income from continuing operations was largely driven by lower revenues and other income ($309.7 million), higher depreciation, depletion and amortization expense (DD&A) ($112.0 million), higher other losses ($93.2 million), higher impairment expense ($52.1 million) and higher selling and general expenses ($27.2 million). These items were partially offset by lower lease operating expenses ($171.7 million), lower income tax expense ($33.7 million), and lower exploration expenses ($21.9 million).

Lower revenues from production were primarily driven by lower average oil prices and lower volumes in the Gulf of America due to downtime and the natural decline of new wells, and was partially offset by increased production in the Eagle Ford Shale due to new wells and improved performance, as well as higher realized natural gas prices in Canada, at the Tupper Montney. Higher DD&A was primarily due to increased production and higher rates in the Eagle Ford Shale, and higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America. Higher other losses were mainly due to unrealized losses on foreign exchange related to our Canada business and were partially offset by lower interest expenses due to no debt repayment fees in the current year. Impairment expense of $115.0 million in 2025 was related to the impairment of the Dalmatian property due to reserve reductions, as certain projects in the field were less competitive for capital allocation. Higher selling and general expenses were due to higher salary and compensation costs in 2025. Lower lease operating expenses were due to lower workovers in the current year, combined with lower operating costs related to the purchase of the Pioneer FPSO. Lower income tax expense was primarily attributable to lower taxable income and was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend. Lower exploration expenses were due to lower dry hole costs in the current period, which related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, and was partially offset by higher exploration, geological, geophysical and other costs related to the Company’s U.S. Offshore and Côte d’Ivoire exploration programs.

For the year ended December 31, 2025, total hydrocarbon production was 188,682 BOEPD, an increase of 2% compared to 2024. The increase was principally due to higher production in the Eagle Ford Shale and Canada Onshore and was partially offset by lower production in the Gulf of America. Increased production in the Eagle Ford Shale was driven primarily by the performance of new wells online in the current year at Karnes and Catarina. Higher production in Canada Onshore related to better well performance at the Tupper Montney. Lower production in the Gulf of America related to planned and unplanned downtime and was partially offset by new wells online.

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Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations

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

(Millions of dollars)

2025

2024

2023

Exploration and production

United States

$

308.5 

$

561.9 

$

905.1 

Canada

54.8 

49.0 

41.6 

Other International

(66.6)

(12.5)

(65.5)

Total exploration and production

296.7 

598.4 

881.2 

Corporate and other

(158.4)

(109.1)

(156.0)

Income from continuing operations

138.3 

489.3 

725.2 

Income (loss) from discontinued operations 1

0.5 

(2.8)

(1.5)

Net income including noncontrolling interest

138.8 

486.5 

723.7 

Net income attributable to noncontrolling interest

34.6 

79.3 

62.1 

Net income attributable to Murphy

$

104.2 

$

407.2 

$

661.6 

1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

E&P Continuing Operations: 2025 vs 2024

The following section of E&P continuing operations excludes the Corporate segment, unless otherwise noted.

Please also refer to “Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities” in the Supplemental Oil and Natural Gas Information section for additional supporting tables.

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

(Millions of dollars)

2025

2024

2023

Revenues and other income

Revenue from production

$

2,689.8 

$

3,014.9 

$

3,376.6 

Sales of purchased natural gas

— 

3.7 

72.2 

Gain on sale of assets and other operating income

17.6 

6.0 

8.0 

Total revenues and other income

2,707.4 

3,024.6 

3,456.8 

Costs and Expenses

Lease operating expenses

765.2 

937.0 

784.4 

Severance and ad valorem taxes

39.2 

39.2 

42.8 

Transportation, gathering and processing

199.7 

210.8 

233.0 

Costs of purchased natural gas

— 

3.1 

51.7 

Depreciation, depletion and amortization

969.4 

856.9 

850.5 

Impairments of assets

115.0 

62.9 

— 

Accretion of asset retirement obligations

57.6 

52.4 

46.0 

Total exploration expenses, including undeveloped lease amortization

111.7 

133.5 

234.8 

Selling and general expenses

46.2 

23.8 

37.7 

Other

16.5 

0.3 

56.9 

Results of operations before taxes

386.9 

704.7 

1,119.0 

Income tax expense

90.2 

106.3 

237.8 

Results of operations (excluding Corporate segment) 1

$

296.7 

$

598.4 

$

881.2 

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

34

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PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Pricing

The following table contains the weighted average sales prices for the three years ended December 31, 2025:

2025

2024

2023

Crude oil and condensate – dollars per barrel

United States - Onshore

$

64.59 

$

75.77 

$

76.96 

United States - Offshore 1

65.69 

76.36 

77.38 

Canada - Onshore 2

57.16 

67.49 

72.84 

Canada - Offshore 2

68.77 

82.22 

84.20 

Other 2

69.26 

77.59 

86.60 

Natural gas liquids – dollars per barrel

United States - Onshore

19.38 

20.20 

19.69 

United States - Offshore 1

20.40 

23.37 

21.94 

Canada - Onshore 2

29.60 

34.14 

35.87 

Natural gas – dollars per thousand cubic feet

United States - Onshore

2.91 

1.90 

2.26 

United States - Offshore 1

3.75 

2.40 

2.78 

Canada - Onshore 2

1.79 

1.59 

2.06 

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

2 U.S. dollar equivalent.

The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2025:

(Average price for the period)

2025

2024

2023

Oil and NGLs

WTI ($/BBL)

$

64.81 

$

75.72 

$

77.62 

Natural gas

Henry Hub ($/MMBTU)

3.54 

2.24 

2.53 

AECO (C$/MCF)

1.68 

1.46 

2.64 

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PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Production Volumes

The following table contains hydrocarbons produced during the three years ended December 31, 2025. For further discussion on volumes, please see “Revenues from Production” section on page 38.

(Barrels per day unless otherwise noted)

2025

2024

2023

Net crude oil and condensate

United States - Onshore

26,186 

21,151 

24,070 

United States - Offshore 1

56,797 

63,047 

73,473 

Canada - Onshore

2,958 

2,868 

2,937 

Canada - Offshore

6,981 

7,251 

3,020 

Other

275 

219 

250 

Total net crude oil and condensate

93,197 

94,536 

103,750 

Net natural gas liquids

United States - Onshore

5,870 

4,442 

4,617 

United States - Offshore 1

4,436 

4,544 

5,924 

Canada - Onshore

521 

597 

681 

Total net natural gas liquids

10,827 

9,583 

11,222 

Net natural gas – thousands of cubic feet per day

United States - Onshore

33,415 

25,028 

25,863 

United States - Offshore 1

51,793 

57,228 

70,239 

Canada - Onshore

422,742 

398,786 

369,906 

Total net natural gas

507,950 

481,042 

466,008 

Total net hydrocarbons - including noncontrolling interest 2

188,682 

184,293 

192,640 

Noncontrolling interest

Net crude oil and condensate – barrels per day

(5,876)

(6,358)

(6,210)

Net natural gas liquids – barrels per day

(217)

(199)

(220)

Net natural gas – thousands of cubic feet per day

(1,767)

(1,942)

(2,089)

Total noncontrolling interest 2

(6,388)

(6,881)

(6,778)

Total net hydrocarbons - excluding noncontrolling interest 2

182,294 

177,412 

185,862 

Estimated total proved net hydrocarbon reserves

- million equivalent barrels 3

730.0 

729.0 

739.5 

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

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

3 Proved reserves at December 31, 2025, 2024 and 2023, include 15.0 MMBOE, 15.9 MMBOE and 15.5 MMBOE, respectively, attributable to NCI.

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Sales Volumes

The following table contains hydrocarbons sold during the three years ended December 31, 2025. For further discussion on volumes, please see “Revenues from Production” section on page 38.

(Barrels per day unless otherwise noted)

2025

2024

2023

Net crude oil and condensate

United States - Onshore

26,186 

21,151 

24,070 

United States - Offshore 1

56,532 

63,612 

73,373 

Canada - Onshore

2,958 

2,868 

2,937 

Canada - Offshore

7,451 

6,445 

2,559 

Other

226 

230 

349 

Total net crude oil and condensate

93,353 

94,306 

103,288 

Net natural gas liquids

United States - Onshore

5,870 

4,443 

4,617 

United States - Offshore 1

4,436 

4,543 

5,924 

Canada - Onshore

521 

597 

681 

Total net natural gas liquids

10,827 

9,583 

11,222 

Net natural gas – thousands of cubic feet per day

United States - Onshore

33,415 

25,028 

25,863 

United States - Offshore 1

51,793 

57,228 

70,239 

Canada - Onshore

422,742 

398,786 

369,906 

Total net natural gas

507,950 

481,042 

466,008 

Total net hydrocarbons - including noncontrolling interest 2

188,838 

184,063 

192,178 

Noncontrolling interest

Net crude oil and condensate – barrels per day

(5,837)

(6,438)

(6,200)

Net natural gas liquids – barrels per day

(217)

(198)

(220)

Net natural gas – thousands of cubic feet per day

(1,767)

(1,942)

(2,089)

Total noncontrolling interest 2

(6,349)

(6,960)

(6,768)

Total net hydrocarbons - excluding noncontrolling interest 2

182,489 

177,103 

185,410 

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

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

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Revenues from Production

The Company’s production revenues by country and product were as follows.

(Millions of dollars)

2025

2024

2023

Revenues from production

United States - Oil

$

1,972.9 

$

2,364.3 

$

2,748.5 

United States - Natural gas liquids

74.5 

71.7 

80.6 

United States - Natural gas

106.5 

67.8 

92.7 

Canada - Oil

248.8 

264.8 

156.7 

Canada - Natural gas liquids

5.6 

7.4 

8.9 

Canada - Natural Gas

275.8 

232.3 

278.2 

Other - Oil

5.7 

6.6 

11.0 

Total revenues from production

$

2,689.8 

$

3,014.9 

$

3,376.6 

Revenues from production in 2025 decreased by $325.1 million compared to 2024. Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline, and downtime for maintenance at Khaleesi. These decreases were partially offset by wells online at Mormont and Neidermeyer in the Gulf of America, improved performance, new wells, and the acquisition of additional working interests in the Eagle Ford Shale, and new wells and improved performance in the Tupper Montney. Higher realized gas pricing in the period was also an offset to the decrease in revenue.

Gain on Sale of Assets and Other Operating Income

Other income was $17.6 million in 2025, an increase of $11.6 million compared to 2024. Higher other income was primarily the result of a gain recognized on contingent consideration related to the 2022 sale of working interests in Block CA-2 in Brunei.

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.

(Millions of dollars)

(Dollars per equivalent barrel)

2025

2024

2023

2025

2024

2023

Lease operating expenses

United States – Onshore

$

125.5 

$

141.9 

$

150.3 

$

9.15 

$

13.02 

$

12.48 

United States – Offshore

451.6 

608.0 

480.4 

17.78 

21.38 

14.46 

Canada – Onshore

128.2 

132.6 

140.3 

4.75 

5.18 

5.89 

Canada – Offshore

57.4 

52.9 

11.5 

21.12 

22.43 

12.30 

Other

2.5 

1.6 

1.9 

29.74 

18.52 

14.94 

Total lease operating expenses

$

765.2 

$

937.0 

$

784.4 

$

11.10 

$

13.91 

$

11.18 

Transportation, gathering and processing

United States – Onshore

$

11.0 

$

9.6 

$

12.7 

$

0.81 

$

0.88 

$

1.05 

United States – Offshore

96.0 

121.3 

144.3 

3.78 

4.27 

4.34 

Canada – Onshore

87.0 

75.5 

72.2 

3.22 

2.95 

3.03 

Canada – Offshore

5.7 

4.4 

3.8 

2.08 

1.85 

4.12 

Total transportation, gathering and processing

$

199.7 

$

210.8 

$

233.0 

$

2.90 

$

3.13 

$

3.32 

Lease operating expenses and transportation, gathering and processing expenses in 2025 decreased by $171.8 million and $11.1 million, respectively, compared to 2024. Lower lease operating expenses were primarily due to lower workover costs in the Gulf of America, lower operating costs as a result of the acquisition of the Pioneer

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FPSO and lower production handling fees. In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, and were partially offset by higher volume related costs.

Depreciation, Depletion and Amortization Expense

The Company’s DD&A expense by geographic area was as follows.

(Millions of dollars)

(Dollars per equivalent barrel)

2025

2024

2023

2025

2024

2023

Depreciation, depletion and amortization expense

United States – Onshore

$

412.3 

$

319.9 

$

316.7 

$

30.02 

$

29.36 

$

26.29 

United States – Offshore

409.8 

389.3 

389.3 

16.13 

13.69 

11.72 

Canada – Onshore

118.1 

123.5 

133.4 

4.38 

4.82 

5.60 

Canada – Offshore

26.7 

22.5 

8.8 

9.81 

9.55 

9.47 

Other

2.5 

1.7 

2.3 

30.23

20.13

18.05

Total depreciation, depletion and amortization expense

$

969.4 

$

856.9 

$

850.5 

$

14.06 

$

12.72 

$

12.12 

DD&A in 2025 increased by $112.5 million compared to 2024. The increase was primarily due to higher sales volumes and higher rates in the Eagle Ford Shale, higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.

Impairment of Assets

In the third quarter of 2025, the Company recorded impairment costs in the Gulf of America totaling $115.0 million ($92.0 million excluding NCI), related to the partial write-down of the Dalmatian field due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

In 2024, the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million. In the first quarter, the Company recognized an impairment expense of $34.5 million for the Calliope field. In the fourth quarter, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field. Both fields were impaired as a result of operational issues that led to reserve reductions.

Exploration Expenses

The Company’s exploration expenses were as follows.

(Millions of dollars)

2025

2024

2023

Exploration expenses

Dry holes and previously suspended exploration costs

$

30.1 

$

73.2 

$

169.8 

Geological and geophysical

36.0 

27.2 

26.1 

Other exploration

33.9 

23.5 

28.0 

Undeveloped lease amortization

11.7 

9.6 

10.9 

Total exploration expenses

$

111.7 

$

133.5 

$

234.8 

Exploration expenses in 2025 decreased by $21.8 million compared to 2024. In 2025, dry holes were related to the operated Civette-1X (Block CI-502) exploration well in Côte d’Ivoire. In 2024, dry holes and previously suspended exploration costs primarily related to the Sebastian #1 (Mississippi Canyon 387) exploration well, the non-operated Orange #1 (Mississippi Canyon 216) exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America. The decrease due to lower dry hole costs was partially offset by increases to geological, geophysical and other exploration costs, related to the Company’s Gulf of America and Côte d'Ivoire exploration programs.

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Selling and General Expenses

Selling and general expenses were $46.2 million in 2025, an increase of $22.4 million compared to 2024. Selling and general expenses were higher due to higher salary and long-term incentive compensation costs primarily related to a higher average share price throughout 2025.

Other Expenses

Total other losses were $16.5 million in 2025, an increase of $16.2 million compared to 2024. The increase was primarily due to no repeat of interest income on outstanding joint interest receivables that was received in 2024.

Income Taxes

Income taxes were $90.2 million in 2025, a decrease of $16.1 million compared to 2024. Lower income taxes were primarily the result of lower pretax income. This was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend.

Corporate: 2025 vs 2024

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of natural gas sold) and corporate overhead not allocated to E&P. Realized and unrealized losses on derivative instruments result from increases in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $158.4 million in 2025, an unfavorable variance of $49.3 million compared to 2024. The unfavorable variance was primarily due to a foreign exchange loss of $29.4 million in 2025 compared to a foreign exchange gain of $45.4 million in 2024, as a result of unrealized exchange rate changes relating to our Canadian subsidiary. This increase was partially offset by lower interest charges in 2025 due to no debt repayment fees in the current year, and a higher income tax benefit attributable to our Canadian segment as a result of larger current-period losses before income taxes, primarily as a result of foreign exchange.

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, as described below. 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.

Cash Flows

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

(Millions of dollars)

2025

2024

2023

Net cash provided by (required by):

Net cash provided by continuing operations activities

$

1,247.8 

$

1,729.0 

$

1,748.8 

Net cash required by investing activities

(1,028.9)

(908.2)

(998.7)

Net cash required by financing activities

(264.1)

(716.5)

(923.7)

Effect of exchange rate changes on cash and cash equivalents

(1.2)

2.2 

(1.2)

Net (decrease) increase in cash and cash equivalents

$

(46.4)

$

106.5 

$

(174.8)

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Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities in 2025 was $481.2 million lower compared to 2024. The decrease was primarily attributable to lower revenue from production ($325.1 million), timing of non-cash working capital ($148.9 million) settlements, changes in other operating activities, net ($68.4 million), primarily due to decreased expenditures for asset retirements, and higher other expenses ($93.2 million), primarily due to Canadian foreign exchange losses, partially offset by lower lease operating expenses ($171.7 million) and lower exploration expenses $21.9 million.

The total reductions of operating cash flows for interest paid (which excludes “Early redemption of debt cost” reported in “Financing Activities”) during the two years ended December 31, 2025, and 2024 were $88.1 million and $78.8 million, respectively. Cash interest paid in 2025 was primarily due to interest payments on outstanding debt. In 2025, cash interest paid was higher than 2024, primarily due to amounts drawn on the RCF. In 2024, cash interest paid was primarily due to interest payments on outstanding debt and accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) for an aggregate redemption amount of $650.1 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2025 was $120.8 million higher compared to 2024. The increase was primarily due to higher property additions ($120.5 million) and higher acquisition capital ($21.0 million), partially offset by proceeds from realization of contingent consideration receivable from the 2022 sale of Brunei assets.

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

Year Ended December 31,

(Millions of dollars)

2025

2024

2023

Property additions and dry hole costs per cash flow statements

$

1,020.6 

$

900.1 

$

1,066.0 

Geophysical and other exploration expenses

65.6 

44.8 

46.0 

Acquisition of oil and natural gas properties per the cash flow statements

29.0 

8.1 

35.6 

Capital expenditure accrual changes and other

102.8 

11.8 

(9.5)

Total capital expenditures

$

1,218.0 

$

964.8 

$

1,138.1 

Total capital expenditures categorized by E&P and corporate activities are presented below.

Year Ended December 31,

(Millions of dollars)

2025

2024

2023

Capital Expenditures

Exploration and production

$

1,196.8 

$

935.7 

$

1,114.0 

Corporate

21.2 

29.1 

24.1 

Total capital expenditures

1,218.0 

964.8 

1,138.1 

Less: acquisition of oil and natural gas properties

29.0 

8.1 

35.6 

Total capital expenditures excluding acquisition of oil and natural gas properties

1,189.0 

956.7 

1,102.5 

Total capital expenditures excluding acquisition of oil and natural gas properties and noncontrolling interest

$

1,157.0 

$

944.7 

$

1,032.3 

Higher capital expenditures in 2025 compared to 2024 were primarily attributable to the Pioneer FPSO purchase in the Gulf of America, exploratory and development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign, and exploratory drilling in Côte d’Ivoire.

Capital expenditures of $1,218.0 million in 2025 were primarily related to development drilling ($551.4 million), field development ($400.2 million) and exploration ($221.7 million) activities. Development activities were mainly in the Gulf of America ($330.8 million), primarily related to the Cascade and Chinook, Mormont,

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Zephyrus, and Other Offshore fields, the Eagle Ford Shale ($365.4 million), the Tupper Montney and the Kaybob Duvernay ($133.9 million), and Vietnam ($98.5 million).

Exploration costs in 2025 were $221.7 million, primarily attributable to activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05, and Hai Su Vang-1X and Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d’Ivoire related to the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.

Cash Required by Financing Activities

Net cash required by financing activities in 2025 decreased by $452.4 million compared to 2024. In 2025, cash used in financing activities was principally for year-to-date cash dividends to shareholders of $1.30 per share ($186.2 million), the repurchase of common shares ($102.6 million), excluding excise tax, distributions to the noncontrolling interest in MP GOM ($63.8 million), and partially offset by net borrowings on the RCF ($100.0 million).

Liquidity

At December 31, 2025, the Company had approximately $1.6 billion of liquidity consisting of $377.2 million in cash and cash equivalents and $1,249.6 million available on its previous RCF with a major banking consortium.

The Company’s previous $1.35 billion RCF was set to expire in October 2029, and as of December 31, 2025, the Company had $100.0 million outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. Borrowings under the RCF were subject to certain interest rates. Please refer to Note F for further details. At December 31, 2025, the interest rate in effect on borrowings under the facility was 6.04%. At December 31, 2025, the Company was in compliance with all covenants related to the RCF. Subsequent to year end, in January, 2026, the Company entered into an Amended RCF, a credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility, with a maturity date in January 2031, which increased and extended the previous RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $152.5 million (2024: $95.2 million), the majority of which was held in Canada ($76.5 million), Brunei ($23.7 million), Côte d’Ivoire ($21.6 million), and Vietnam ($8.5 million). In addition, approximately $7.8 million and $7.0 million of cash was held in Mexico and the U.K., respectively. 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. See Note H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the U.S.

Working Capital

(Millions of dollars)

2025

2024

Working capital

Total current assets

$

816.7 

$

785.3 

Total current liabilities

1,062.7 

942.8 

Net working capital liability

$

(246.0)

$

(157.5)

As of December 31, 2025, net working capital had an unfavorable decrease of $88.5 million compared to December 31, 2024. The decrease was primarily attributable to higher accounts payable ($100.0 million), higher operating lease liabilities ($25.6 million), and a lower cash balance ($46.4 million), partially offset by higher accounts receivable ($74.2 million). Higher accounts payable were primarily due to the timing of payments for certain drilling activities and ongoing workover projects. Higher operating lease liabilities were primarily due to the addition of a new drilling rig and support vessels in Vietnam, partially offset by the purchase of the Pioneer FPSO and normal amortization of leases. Higher accounts receivable were due primarily to timing of partner billing and related cash calls, partially offset by lower pricing.

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Capital Employed

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

December 31, 2025

December 31, 2024

(Millions of dollars)

Amount

%

Amount

%

Capital employed

Long-term debt

$

1,382.6 

21.3 

%

$

1,274.5 

19.7 

%

Murphy shareholders' equity

5,118.4 

78.7 

%

5,194.3 

80.3 

%

Total capital employed

$

6,501.0 

100.0 

%

$

6,468.8 

100.0 

%

As of December 31, 2025, long-term debt increased by $108.1 million compared to December 31, 2024, primarily as a result of amounts drawn on the RCF. As of December 31, 2025, the fixed-rate notes had a weighted average maturity of 8.3 years and a weighted average coupon of 6.1%. Refer to Note F for additional details.

Murphy’s shareholders’ equity decreased by $75.9 million in 2025 primarily due to dividends ($186.2 million) and shares repurchased ($100.8 million), including excise tax, partially offset by foreign currency translation ($74.0 million), net income ($104.2 million), and awarded restricted stock ($22.4 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity" on page 72 of this Form 10-K report.

Other Balance Sheet Activity - Long-Term Assets and Liabilities

Other significant changes in Murphy’s balance sheet at the end of 2025, compared to 2024 are discussed below.

Property, plant and equipment, net of depreciation, increased $81.7 million principally due to capital expenditures in the year, partially offset by DD&A expense ($977.8 million) and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the “Cash Required by Investing Activities” section.

Murphy had commitments for capital expenditures of approximately $551.2 million at December 31, 2025 (2024: $417.0 million). This amount primarily related to approved expenditures of $127.5 million in Vietnam for the Lac Da Vang (Golden Camel) field development project, $45.0 million for exploration activities in Côte d’Ivoire, $82.6 million in the Eagle Ford Shale, $245.3 million relating to Gulf of America interests, primarily related to Cascade and Chinook operated field and exploration activities, as well as $49.8 million relating to interests in Canada Onshore, primarily at the Kaybob Duvernay.

Operating lease assets increased $27.9 million principally due to lease additions in Vietnam, partially offset by the depreciation of these assets.

Deferred income tax liabilities increased $42.5 million due to utilization of our net operating loss, partially offset by other capital-related tax effects.

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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 a substitute for net income or cash provided by operating activities as determined in accordance with GAAP.

The following table reconciles net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

Year Ended December 31,

(Millions of dollars, except per share amounts)

2025

2024

2023

Net income attributable to Murphy (GAAP) 1

$

104.2 

$

407.2 

$

661.6 

Discontinued operations (income) loss

(0.5)

2.8 

1.5 

Net income from continuing operations

103.7 

410.0 

663.1 

Adjustments:

Impairment of assets 1

92.0 

62.9 

— 

Foreign exchange (gain) loss

29.4 

(45.4)

10.9 

Unrealized (gain) loss on derivative instruments

(1.7)

1.7 

— 

Write-off of previously suspended exploration well

— 

26.1 

17.1 

Unrealized loss on contingent consideration

— 

— 

7.1 

Asset retirement obligation losses

— 

— 

16.9 

Refinancing and early redemption of debt costs (non-cash)

— 

3.7 

— 

Total adjustments, before taxes

119.7 

49.0 

52.0 

Income tax (benefit) expense related to adjustments

(26.4)

(8.3)

(6.4)

Tax benefits on investments in foreign areas

— 

(34.0)

— 

Total adjustments, after taxes

93.3 

6.7 

45.6 

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)

$

197.0 

$

416.7 

$

708.7 

Net income from continuing operations per average diluted share

$

0.72 

$

2.72 

$

4.23 

Adjusted net income from continuing operations per average diluted share (Non-GAAP)

$

1.37 

$

2.76 

$

4.52 

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

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The following table reconciles net income attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.

Year Ended December 31,

(Millions of dollars)

2025

2024

2023

Net income attributable to Murphy (GAAP) 1

$

104.2 

$

407.2 

$

661.6 

Income tax expense

44.6 

78.3 

195.9 

Interest expense, net

96.1 

105.9 

112.4 

Depreciation, depletion and amortization expense ¹

946.8 

833.1 

836.7 

EBITDA attributable to Murphy (Non-GAAP)

$

1,191.7 

$

1,424.5 

$

1,806.6 

Exploration expenses 1

111.6 

133.5 

204.6 

EBITDAX attributable to Murphy (Non-GAAP)

$

1,303.3 

$

1,558.0 

$

2,011.2 

EBITDA attributable to Murphy (Non-GAAP)

$

1,191.7 

$

1,424.5 

$

1,806.6 

Impairment of asset 1

92.0 

62.9 

— 

Foreign exchange (gain) loss

29.4 

(45.4)

10.8 

Accretion of asset retirement obligations ¹

51.5 

46.9 

41.0 

Unrealized (gain) loss on derivative instruments

(1.7)

1.7 

— 

Write-off of previously suspended exploration well

— 

26.1 

17.1 

Asset retirement obligation losses

— 

— 

16.9 

Unrealized loss on contingent consideration

— 

— 

7.1 

Discontinued operations (income) loss

(0.5)

2.8 

1.5 

Adjusted EBITDA attributable to Murphy (Non-GAAP)

$

1,362.4 

$

1,519.5 

$

1,901.0 

Other exploration expenses 2

111.6 

107.4

187.5

Adjusted EBITDAX attributable to Murphy (Non-GAAP)

$

1,474.0 

$

1,626.9 

$

2,088.5 

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

2 Other exploration expenses consist of exploration expenses as reported in the Consolidated Statements of Operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.

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Management uses 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.

Year Ended December 31,

(Millions of dollars)

2025

2024

2023

Net cash provided by continuing operations activities (GAAP)

$

1,247.8 

$

1,729.0 

$

1,748.8 

Exclude: (decrease) increase in non-cash working capital

74.1 

(74.9)

99.4 

Operating cash flow excluding working capital adjustments

1,321.9 

1,654.1 

1,848.2 

Less: property additions and dry hole costs 1

(1,020.6)

(900.1)

(1,066.0)

Free cash flow (Non-GAAP)

$

301.3 

$

754.0 

$

782.2 

Less: cash dividends paid

(186.2)

(180.0)

(171.0)

Less: distributions to noncontrolling interest

(63.8)

(118.6)

(29.4)

Less: debt costs

(0.4)

(40.6)

— 

Less: contingent consideration payment

— 

— 

(60.2)

Less: withholding tax on stock-based incentive awards

(9.8)

(25.3)

(14.3)

Less: acquisition of oil and natural gas properties

(29.0)

(8.0)

(35.6)

Adjusted free cash flow (Non-GAAP)

$

12.1 

$

381.5 

$

471.7 

1 Property additions for the year ended December 31, 2025 include a payment of $125.0 million for the Pioneer FPSO in the U.S. Offshore, including amounts attributable to the noncontrolling interest in MP GOM.

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Environmental, Health and Safety Matters

Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, auditing and assessments, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and approved by a Health, Safety, Environment and Corporate Responsibility Committee consisting of certain members of the Board.

The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations. Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.

The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other GHG emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.

Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the “Business” section beginning page 9.

Climate Change and Emissions

The world’s population and standard of living are growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of GHG, which could raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the TCFD framework. While oversight of the TCFD framework has undergone changes, including relating to the role of the International Financial Reporting Standards Foundation in overseeing the framework, the TCFD framework continues to inform climate-related reporting practices. Murphy’s disclosures related to its alignment with the TCFD framework are included in the Company’s 2025 Sustainability Report issued on August 6, 2025, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2025, inflation in the U.S. and in other countries where the Company operates began to moderate relative to the sustained higher inflation seen since 2021. However, U.S. and global trade policy is continually developing, and it is unclear whether this trend will continue or reverse as we enter 2026 and beyond. The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ members’ production levels and/or attitudes of traders concerning supply and demand in the future. Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.

To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and

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commitments and therefore is partially protected from potential increases in the price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher costs. Murphy continues to strive toward safely executing our work in an ever-increasingly efficient manner to mitigate potential inflationary pressures in its business.

Natural gas prices are also affected by supply and demand factors, which are often influenced by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas. Natural gas prices can also be impacted by the demand for lower-carbon energy sources.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.

Oil and natural gas proved reserves – Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain). Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 

Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use an unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas prices and reserve assumptions when making its own internal economic property evaluations. Changes in oil and natural gas prices can lead to a decision to start up or shut in production, which can lead to revisions to reserves quantities. 

Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligation (ARO) liabilities. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods. 

The Company’s proved reserves of oil and natural gas are presented on pages 111 to 120 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), and commercially available technologies, to establish “reasonable certainty” of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies. 

Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of

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and confidence in Murphy’s proved reserves estimates. It was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2025 beginning on pages 4 and 111 of this Form 10-K report.

Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheets to ensure that they are fairly presented. The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from undiscounted future net cash flows. 

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs and future inflation levels. 

The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment. 

Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections. 

Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. 

The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. 

In 2025, the Company recognized a pretax non-cash impairment charge of $115.0 million ($92.0 million excluding NCI) to reduce the carrying value at the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation.

In 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties. The Company recognized impairments of $34.5 million, related to the Calliope field, and $28.4 million, related to the Nearly Headless Nick field, both in the Gulf of America. Both impairment charges were due to subsurface issues that led to reserve reductions.

See also Note D for further discussion of impairment charges.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company; and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

The Company has deferred tax assets mostly relating to U.S. net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant and equipment.

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The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduces such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and negative evidence. Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.

As of December 31, 2025 the Company had a U.S. deferred tax asset associated with net operating losses of $225.0 million. In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for oil and natural gas, (b) estimated reserves for oil and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.

Accounting for retirement and postretirement benefit plans – Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate, which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields as of December 31, 2025, the Company has used a weighted average discount rate of 5.40% at year end 2025 for the primary U.S. plans. This weighted average discount rate is 0.2% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 7.70% for the primary U.S. plan and periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2026 are expected to be $0.4 million lower than in 2025 primarily due to higher actual return on plan assets, partially offset by an increase in the benefit obligations at December 31, 2025 compared to the prior year.

In 2025, the Company paid $25.1 million into various retirement plans and $12.9 million into postretirement plans. In 2026, the Company is expecting to fund payments of approximately $24.5 million into various retirement plans and $4.7 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.

Recent Accounting Pronouncements

See Note B in our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

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Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans and other long-term liabilities. Total payments due after 2025 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.

(Millions of dollars)

Amount of Obligations

Total

2026

2027 - 2028

2029 - 2030

After 2030

Debt, excluding finance leases and interest

$

1,384.8 

$

— 

$

227.5 

$

217.5 

$

939.8 

Operating and finance leases

1,024.8 

318.9 

215.8 

123.0 

367.1 

Capital expenditures, drilling rigs and other ¹

1,648.0 

761.1 

252.0 

160.2 

474.7 

Other long-term liabilities, including debt interest ²

2,344.6 

129.6 

230.6 

450.2 

1,534.2 

Total

$

6,402.2 

$

1,209.6 

$

925.9 

$

950.9 

$

3,315.8 

1 Capital expenditures, drilling rigs and other includes $28.1 million, $25.4 million, $7.7 million, $1.0 million and $0.6 million in 2026 for approved capital projects in non-operated interests in the Gulf of America, the Eagle Ford Shale, Canada Offshore, Brunei, and Canada Onshore, respectively.

Also includes $72.2 million (2026), $141.1 million (2027 - 2028), $81.0 million (2029 - 2030) and $235.9 million (After 2030) for pipeline transportation commitments in Canada.

Also includes $3.7 million (2026), $7.5 million (2027 - 2028), $7.4 million (2029 - 2030) and $14.3 million (After 2030) for long-term take-or-pay commitments relating to natural gas processing in Canada.

Also includes $23.6 million (2026), $47.1 million (2027 - 2028), $48.1 million (2029 - 2030) and $176.8 million (After 2030) for the purpose of supporting future production activities in Vietnam.

2 Other long-term liabilities includes debt interest and future cash outflows for ARO liabilities.

The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that require future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $211.8 million as of December 31, 2025.

Subsequent to the balance sheet date, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In January 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its 6.500% senior notes due 2034 (2034 Notes), used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. See Note F for additional information.

Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Canada Onshore transportation and processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

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Outlook

The oil and natural gas industry is impacted by global commodity pricing. 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 on revenues, on page 38, lower average crude oil price during 2025 directly impacted the Company’s product sales revenue.

As of close on February 23, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the table below.

2026

2027

NYMEX WTI ($/BBL)

$

64.90 

$

62.02 

NYMEX Henry Hub ($/MMBTU)

3.39

3.72

AECO (US$ Equivalent/MCF)

1.36

1.90

In 2025, liquids from continuing operations represented approximately 55% of total hydrocarbons produced on a barrels of oil equivalent basis. In 2026, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 56%. If the prices for crude oil and natural gas are lower in 2026 or beyond, this will have an unfavorable impact on the Company’s operating profits; likewise, if prices are higher, this will have a favorable impact. The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

The Company currently expects average daily production in 2026 to be between 173,000 and 181,000 BOEPD (including a noncontrolling interest of 6,000 BOEPD). If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.

The oil and natural gas industry and the Company continue to observe higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.

We cannot predict what impact economic factors (including, but not limited to, inflation, evolving trade policy, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash flows.

The Company’s capital expenditure spend for 2026 is expected to be between $1,200 million and $1,300 million, excluding NCI. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 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 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 Framework” section of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024. The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock. As of December 31, 2025, the Company had $550.1 million of its common stock remaining available to repurchase under the program.

Subsequent to the balance sheet date, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In January 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its 2034 Notes, used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. In addition, the Company entered into an amendment to its credit agreement which increased its RCF capacity from $1.35 billion to $2.0 billion and extended the term of the agreement to 2031. See Note F for additional information on these transactions.

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On January 28, 2026, the Board of Directors declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $0.35 per share, which on an annualized basis would be $1.40 per share. The dividend is payable on March 2, 2026, to stockholders of record as of February 17, 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 RCF (see Note F).

As of February 23, 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.

Volumes

(MMCF/D)

Price/MCF

Remaining Period

Area

Commodity

Type

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

50

C$3.03

1/1/2026

3/31/2026

Canada

Natural Gas

Fixed price forward sales

78

C$2.94

4/1/2026

6/30/2026

Canada

Natural Gas

Fixed price forward sales

78

C$2.94

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

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Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and intent to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other environmental, social and governance matters, make capital expenditures, pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply and demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or markets of health pandemics and related government responses; natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; cyber attacks and other cybersecurity risks; any failure to obtain necessary regulatory approvals; the impact of current and future laws, rulings and governmental regulations; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Item 1A. Risk Factors”, which begins on page 13 of this Annual Report on Form 10-K. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Each forward-looking statement contained in this report speaks only as of the date of this report. Except as required by applicable law, Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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