What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2024-02-23 compared with 2023-02-27 · 558 added, 117 removed, 34 unchanged (95% of the section changed)

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s common stock is traded on the New York Stock Exchange using “MUR” as the trading symbol.

There were 1,974 stockholders of record as of December 31, 2023.

Information on dividends per share by quarter for 2023 and 2022 are reported on page 119 of this Form 10-K report.

Issuer Purchase of Equity Securities:

The following table summarizes repurchases of our common stock occurring in the fourth quarter 2023.

Period Total Number of Shares Purchased Average Price Paid Per Share 1

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs 2,3

(in thousands)

October 1 through October 31, 2023 – $ – – $ 525,000

November 1 through November 30, 2023 1,154,348 $ 43.29 1,154,348 $ 475,000

December 1 through December 31, 2023 572,288 $ 43.66 572,288 $ 450,000

1 Amounts exclude 1% excise tax and fees on share repurchases.

2 In August 2022, the Board authorized an initial share repurchase program of up to $300 million of the Company’s common stock.

On October 30, 2023, the Company authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.

Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws.

This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion.

3 Maximum approximate dollar values reported represent amounts at end of the month.

During 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program in open-market transactions for $150.0 million, excluding taxes and fees.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued

2 unchanged sentences

XOP Index reports a comprehensive view of the oil and gas exploration and production segment of the S&P Total Market Index which is more comparable for the Company than the S&P 500 Index.

Our peer group for 2023 is presented in the table below.

Callon Petroleum Company, Matador Resources Company and SM Energy Company were added to Murphy’s peer group in 2023 and CNX Resources Corporation was removed.

This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference.

The companies in the peer group included:

APA Corporation Hess Corporation PDC Energy, Inc.

Coterra Energy Inc.

Kosmos Energy Ltd.

APA Corporation Kosmos Energy Ltd.

Range Resources Corporation

CNX Resources Corporation Marathon Oil Corporation Southwestern Energy Company

Callon Petroleum Company

Marathon Oil Corporation SM Energy Company

Coterra Energy Inc.

Matador Resources Company

Southwestern Energy Company

Devon Energy Corporation Ovintiv Inc.

Talos Energy Inc.

Hess Corporation PDC Energy Inc.

2018 2019 2020 2021 2022 2023

3 unchanged sentences

XOP Index 100 112 72 135 215 215

1 PDC Energy Inc.

was acquired in 2023 and therefore has been excluded from the above table and graph of cumulative total return.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company.

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 2021 results and year-over-year comparisons between 2022 and 2021 are not included in this Form 10-K and can be found in Item 7 of the 2022 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 gas exploration and production company with both onshore and offshore operations and properties.

The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S.

and Canada and explores for crude oil, natural gas and natural gas liquids 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.

In 2022, a combination of demand recovery from the COVID-19 pandemic, geopolitical uncertainty and market disruption from the Russia/Ukraine conflict and lack of investment in the exploration and production sector contributed to increased crude oil and natural gas benchmark prices compared to 2021.

Prices declined in the second half of 2022, due to increased supply related to the Strategic Petroleum Reserve oil release and ongoing concerns related to a possible economic slowdown and demand from China.

Similar to the overall inflation in the wider economy, the oil and gas industry, and hence the Company, is observing higher costs for goods and services used in exploration and production operations.

Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs.

Significant Company operating and financial highlights during and at the end of 2022 were as follows:

• Generated net income of $965 million and $2,180.2 million of net cash provided by operating activities and $1,070.8 million of adjusted cash flow 1 ;

• Produced 175 thousand barrels of oil equivalent (BOE) per day (167 thousand excluding noncontrolling interest, NCI) and completed the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico with seven wells brought online;

• Acquired additional working interest in non-operated Lucius and Kodiak fields in the Gulf of Mexico for $128.5 million;

• Announced capital allocation framework 2 and reduced total debt by approximately $650 million, a 26% debt reduction in the year;

• Doubled the cash dividend since the fourth quarter of 2021 to $1.00 per share annualized;

• Achieved 98% total proved reserve replacement with year-end proved reserves of 715.4 million barrels of oil equivalent (697.2 million excluding NCI).

1 Adjusted cash flow is a non-GAAP financial measure calculated as cash flow from operations less capital expenditures ($1,109.4 million).

Management believes adjusted cash flow is important to provide as it is used by management to evaluate the Company’s ability to generate additional cash from business operations after providing for capital investments.

Adjusted cash flow is a non-GAAP financial measure and should not be considered a substitute for other financial measures as determined in accordance with accounting principles generally accepted in the United States of America.

Additionally, our definition of adjusted cash flow is limited and does not represent residual cash flows available for other discretionary expenditures as the measure does not deduct the payments required for debt service and other obligations.

Therefore, we believe it is important to view adjusted cash flow as supplemental to our entire statement of cash flows.

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

Significant Company financial and operational highlights during 2023 were as follows:

• Generated net income of $661.6 million and net cash provided by operating activities of $1,748.8 million;

• Produced 193 thousand barrels of oil equivalent (BOE) per day (186 thousand excluding noncontrolling interest, NCI);

• Sanctioned the Lac Da Vang field development project in Vietnam;

• Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire;

• Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico;

• Acquired an 8% working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for a purchase price of approximately $13 million, net of closing adjustments;

• Resumed operations at non-operated Terra Nova field in offshore Canada during the fourth quarter of 2023, with production ramping up through first quarter 2024;

• Advances made under the capital allocation framework 1 :

◦ Early debt retirement of approximately $500 million, a 27% debt reduction in the year

◦ Repurchased shares of common stock under the share repurchase program for $150 million, excluding excise taxes, commissions and fees

◦ Increased cash dividends by 10% since the fourth quarter of 2022 to $0.275 per share, or $1.10 per share annualized

• Achieved 134% (139% excluding NCI) total proved reserve replacement with year-end proved reserves of 739.5 million barrels of oil equivalent (724.0 million excluding NCI).

1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.

Throughout this section, the term, ‘excluding noncontrolling interest’ or ‘excluding NCI’ refers to amounts attributable to Murphy.

Unless noted, amounts include noncontrolling interest.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and NGL.

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

On October 30, 2023, the initial share repurchase program of $300 million of the Company’s common stock was increased by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.

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

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company.

In 2022, liquids from continuing operations represented approximately 62% of total hydrocarbons produced on an energy equivalent basis.

In 2023, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 63%.

If the prices for crude oil and natural gas are lower in 2023 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.

Oil prices were higher in 2022 compared to the 2021 and 2020 periods.

The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $94.23 in 2022, $67.91 in 2021 and $39.40 in 2020.

In 2023, the WTI price has thus far been below the comparable period in 2022, however, higher than the comparable period 2021.

WTI average price for 2022 increased 39% over the prior year principally as a result of demand recovery from the COVID-19 pandemic, geopolitical uncertainty and market disruption following the Russia/Ukraine conflict and market concerns over supply shortfalls as discussed above.

The most common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH), Heavy Louisiana Sweet (HLS) and Brent.

The New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged $6.38 in 2022, $3.84 in 2021 and $1.99 in 2020.

The 2022 NYMEX natural gas price was higher compared to 2021 and NYMEX prices in 2023 have thus far been below the comparable period in 2022.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids, and natural gas in the United States and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and natural gas liquids.

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 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, 2023, the Company’s net income from continuing operations was $725.2 million, a decrease of $415.6 million compared to 2022.

Lower net income from continuing operations was largely driven by lower revenues and other income ($472.5 million), higher lease operating expenses ($105.1 million) and higher exploration expenses ($101.6 million), partially offset by lower other operating expense ($91.0 million) and lower income tax expense ($113.5 million).

Lower revenues and other income resulted from overall lower pricing partially offset by overall higher sales volumes and lower losses on derivative instruments.

Higher lease operating expenses were related to higher sales volumes as well as additional costs for workover and maintenance activities at Gulf of Mexico operations.

Higher exploration costs were the result of dry hole expense for the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells, that did not find commercial hydrocarbons in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire, and the expensing of previously suspended exploration costs for the Cholula-1EXP well in Mexico.

No losses were recorded in 2023 on derivative instruments as no fixed price derivative swaps or collar contracts were in effect during the period.

Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.

Lower income tax expense was the result of lower pre-tax income.

For the year ended December 31, 2023, total hydrocarbon production was 192,640 barrels of oil equivalent per day, an increase of 10% compared to 2022.

The increase was principally due to new well production volumes in the Gulf of Mexico from the Khaleesi, Mormont, Samurai field development project, new well production from Tupper Montney and lower royalty rates, partially offset by lower production volumes at other fields in the Gulf of Mexico due to additional downtime.

Results of Operations

Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.

Years Ended December 31,

(Millions of dollars, except EPS )

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

( Millions of dollars )

2023 2022 2021

Income (loss) from continuing operations before income taxes $ 1,450.3 $ 42.9 $ (1,549.0)

Net income (loss) attributable to Murphy 965.0 (73.7) (1,148.8)

Diluted EPS 6.13 (0.48) (7.48)

Income (Loss) from continuing operations attributable to Murphy 967.1 (72.4) (1,141.6)

Diluted EPS 6.14 (0.47) (7.43)

(Loss) income from discontinued operations (2.1) (1.2) (7.2)

Diluted EPS (0.01) (0.01) (0.05)

For the year ended December 31, 2022, the Company produced 175 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.

The Company invested $1,183.2 million in capital expenditures (on a value of work done basis) for the year ended December 31, 2022, which included $25.9 million attributable to noncontrolling interest and $128.5 million for capital acquisitions.

The Company reported net income from continuing operations of $1,140.8 million for the year ended December 31, 2022.

This amount includes income attributable to noncontrolling interest of $173.7 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $169.6 million and after-tax losses on contingent consideration (see Note P ) of $61.6 million.

In 2022, the Company achieved first production from the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico and acquired a 3.4% working interest in the Lucius field and an 11.0% working interest in the Kodiak field in the Gulf of Mexico, with both acquisitions having no noncontrolling interests.

For the year ended December 31, 2021, the Company produced 167 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.

The Company invested $711.2 million in capital expenditures (on a value of work done basis) for the year ended December 31, 2021, which included $23.0 million attributable to noncontrolling interest and $17.3 million to fund the development of the King’s Quay

Exploration and production

United States $ 905.1 $ 1,521.9 $ 766.3

Canada 41.6 134.2 (16.1)

Other International (65.5) (77.0) (33.5)

Total exploration and production

881.2 1,579.1 716.7

Corporate and other (156.0) (438.3) (668.0)

Income from continuing operations

725.2 1,140.8 48.7

Loss from discontinued operations 1

(1.5) (2.1) (1.2)

Net income including noncontrolling interest

723.7 1,138.7 47.5

Net income attributable to noncontrolling interest

62.1 173.7 121.2

Net income attributable to Murphy

$ 661.6 $ 965.0 $ (73.7)

1 The Company has presented its former U.K.

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

E&P Continuing Operations:

The following section of Exploration and Production (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.

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

floating production system (FPS).

The Company reported net income from continuing operations of $48.8 million (which included post tax impairment charges of $151.5 million and income attributable to noncontrolling interest of $121.2 million) for the year ended December 31, 2021.

The following are summarized income statements for E&P continuing operations.

(Millions of dollars) 2023 2022 2021

Revenues and other income

Revenue from production

$ 3,376.6 $ 4,038.5 $ 2,801.2

Sales of purchased natural gas

8.0 26.7 17.5

Total revenues and other income

3,456.8 4,246.9 2,818.7

Cost and Expenses

Lease operating expenses 784.4 679.3 539.5

Severance and ad valorem taxes 42.8 57.0 41.2

Transportation, gathering and processing 233.0 212.7 187.0

Costs of purchased natural gas 51.7 172.0 –

Depreciation, depletion and amortization 850.5 763.9 782.1

Impairments of assets – – 189.3

Accretion of asset retirement obligations 46.0 46.2 46.6

Total exploration expenses 234.8 133.1 69.0

Selling and general expenses 37.7 44.5 43.6

Other 56.9 141.8 31.0

Results of operations before taxes 1,119.0 1,996.4 889.4

Income tax provisions

237.8 417.3 172.7

Results of operations (excluding Corporate segment) 1

$ 881.2 $ 1,579.1 $ 716.7

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

The following table contains the weighted average sales prices for the three years ended December 31, 2023.

(Weighted average sales prices)

2023 2022 2021

Crude oil and condensate – dollars per barrel

United States - Onshore $ 76.96 $ 96.00 $ 66.90

United States - Offshore 1

77.38 94.21 66.93

Canada - Onshore 2

72.84 89.88 61.79

Canada - Offshore 2

84.20 107.47 71.39

86.60 94.37 69.21

Natural gas liquids – dollars per barrel

United States - Onshore $ 19.69 $ 33.85 $ 26.97

United States - Offshore 1

21.94 36.01 29.14

Canada - Onshore 2

35.87 55.65 40.18

Natural gas – dollars per thousand cubic feet

United States - Onshore $ 2.26 $ 6.04 $ 3.83

United States - Offshore 1

2.78 6.97 3.67

Canada - Onshore 2

2.06 2.76 2.43

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

dollar equivalent.

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

The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2023.

(Average price for the period) 2023 2022 2021

WTI ($/BBL) $ 77.62 $ 94.23 $ 67.91

NYMEX ($/MMBTU) 2.53 6.38 3.84

AECO (C$/MCF) 2.64 5.31 3.63

Production Volumes

The following table contains hydrocarbons produced during the three years ended December 31, 2023.

For further discussion on volumes, please see Revenues from Production section on page 37 .

(Barrels per day unless otherwise noted) 2023 2022 2021

Net crude oil and condensate

United States - Onshore

24,070 24,437 25,655

United States - Offshore 1

73,473 65,411 60,717

Canada - Onshore

2,937 4,005 5,312

Canada - Offshore

3,020 2,812 3,765

Other 250 700 256

Total net crude oil and condensate

103,750 97,365 95,705

Net natural gas liquids

United States - Onshore

4,617 5,181 5,092

United States - Offshore 1

5,924 4,597 4,176

Canada - Onshore

681 903 1,117

Total net natural gas liquids

11,222 10,681 10,385

Net natural gas – thousands of cubic feet per day

United States - Onshore

25,863 29,050 28,565

United States - Offshore 1

70,239 63,380 61,240

Canada - Onshore

369,906 310,230 277,790

Total net natural gas

466,008 402,660 367,595

Total net hydrocarbons - including NCI 2,3

192,640 175,156 167,356

Noncontrolling interest

Net crude oil and condensate – barrels per day (6,210) (7,452) (8,623)

Net natural gas liquids – barrels per day (220) (280) (303)

Net natural gas – thousands of cubic feet per day (2,089) (2,468) (3,236)

Total noncontrolling interest 2,3

(6,778) (8,143) (9,465)

Total net hydrocarbons - excluding NCI 2,3

185,862 167,013 157,891

Estimated total proved net hydrocarbon reserves

- million equivalent barrels 3,4

739.5 715.4 716.9

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.

4 December 31, 2023, 2022 and 2021, include 15.5 MMBOE, 18.2 MMBOE and 18.4 MMBOE, respectively, relating to

noncontrolling interest.

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

Sales Volumes

The following table contains hydrocarbons sold during the three years ended December 31, 2023.

For further discussion on volumes, please see Revenues from Production section on page 37 .

(Barrels per day unless otherwise noted) 2023 2022 2021

Net crude oil and condensate

United States - Onshore

24,070 24,437 25,655

United States - Offshore 1

73,373 64,840 60,544

Canada - Onshore

2,937 4,005 5,312

Canada - Offshore

2,559 3,002 3,559

Other 349 663 195

Total net crude oil and condensate

103,288 96,947 95,265

Net natural gas liquids

United States - Onshore

4,617 5,181 5,092

United States - Offshore 1

5,924 4,597 4,176

Canada - Onshore

681 903 1,117

Total net natural gas liquids

11,222 10,681 10,385

Net natural gas – thousands of cubic feet per day

United States - Onshore

25,863 29,050 28,565

United States - Offshore 1

70,239 63,380 61,240

Canada - Onshore

369,906 310,230 277,790

Total net natural gas

466,008 402,660 367,595

Total net hydrocarbons - including NCI 2,3

192,178 174,738 166,916

Noncontrolling interest

Net crude oil and condensate – barrels per day (6,200) (7,369) (8,605)

Net natural gas liquids – barrels per day (220) (280) (303)

Net natural gas – thousands of cubic feet per day (2,089) (2,468) (3,236)

Total noncontrolling interest 2,3

(6,768) (8,060) (9,447)

Total net hydrocarbons - excluding NCI 2,3

185,410 166,678 157,469

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

Revenues from Production

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

(Millions of dollars) 2023 2022 2021

Revenues from production

United States - Oil $ 2,748.5 $ 3,085.9 $ 2,105.2

United States - Natural gas liquids 80.6 124.4 94.6

United States - Natural gas

92.7 225.3 121.7

Canada - Oil 156.7 249.2 212.5

Canada - Natural gas liquids 8.9 18.3 16.4

Canada - Natural Gas

278.2 312.6 245.9

11.0 22.8 4.9

Total revenues from production

$ 3,376.6 $ 4,038.5 $ 2,801.2

Revenues from production in 2023 decreased by $661.9 million compared to 2022.

Lower revenues from U.S.

E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher overall sales volumes from the Gulf of Mexico.

Higher sales volumes were driven by new well performance from the Khaleesi, Mormont, Samurai field development project, and were partially offset by lower sales volumes at other fields.

Lower revenues from Canadian E&P was primarily attributable to lower realized prices and lower sales volumes at Kaybob Duvernay partially offset by higher sales volumes at Tupper Montney.

Lower sales volumes at Kaybob Duvernay were primarily due to the divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, as well as natural declines.

Higher sales volumes at Tupper Montney were the result of new wells coming online in 2023, improved well performance, and lower royalty rates.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments.

Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 34.

Other income was $8.0 million in 2023, a decrease of $18.7 million compared to 2022.

Lower other income was primarily the result of a gain on sale of the Thunder Hawk field in the third quarter of 2022.

Management’s Discussion and Analysis of Financial Condition and 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:

(Millions of dollars) (Dollars per equivalent barrel)

2023 2022 2021 2023 2022 2021

Lease operating expenses

United States – Onshore

$ 150.3 $ 137.6 $ 115.7 $ 12.48 $ 10.94 $ 8.93

United States – Offshore

480.4 385.1 290.7 14.46 13.19 10.63

Canada – Onshore 140.3 139.5 119.4 5.89 6.75 6.20

Canada – Offshore 11.5 15.6 16.9 12.30 14.20 13.04

Other 1.9 1.5 (3.2) 14.94 6.25 (44.94)

Total lease operating expenses $ 784.4 $ 679.3 $ 539.5 $ 11.18 $ 10.65 $ 8.86

Transportation, gathering and processing

United States – Onshore

$ 12.7 $ 18.4 $ 26.1 $ 1.05 $ 1.47 $ 2.02

United States – Offshore

144.3 123.8 100.4 4.34 4.24 3.67

Canada – Onshore 72.2 65.3 57.4 3.03 3.16 2.98

Canada – Offshore 3.8 5.2 3.1 4.12 4.76 2.36

Total transportation, gathering and processing $ 233.0 $ 212.7 $ 187.0 $ 3.32 $ 3.34 $ 3.07

Lease operating expenses and transportation, gathering and processing expenses in 2023 increased by $105.1 million and $20.3 million, respectively, compared to 2022.

Higher lease operating expenses and increased transportation, gathering and processing expenses from U.S.

E&P were primarily due to increased sales volumes and higher operating expenses for additional workover and maintenance activities from the Gulf of Mexico operations.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization expense by geographic area were as follows:

(Millions of dollars) (Dollars per equivalent barrel)

2023 2022 2021 2023 2022 2021

Depreciation, depletion and amortization expense

United States – Onshore

$ 316.7 $ 321.4 $ 356.4 $ 26.29 $ 25.55 $ 27.50

United States – Offshore

389.3 295.6 260.1 11.72 10.12 9.51

Canada – Onshore 133.4 128.1 147.2 5.60 6.20 7.64

Canada – Offshore 8.8 13.4 16.6 9.47 12.25 12.80

Other 2.3 5.4 1.8 18.05 22.19 26.78

Total depreciation, depletion and amortization expense

$ 850.5 $ 763.9 $ 782.1 $ 12.12 $ 11.98 $ 12.84

Depreciation, depletion and amortization expense (DD&A) in 2023 increased by $86.6 million compared to 2022.

Higher DD&A was primarily the result of higher sales volumes and higher rates from the Gulf of Mexico.

DD&A from Canadian E&P increased at Tupper Montney due to higher sales volumes and higher rates, substantially offset by lower sales volumes and lower rates at Kaybob Duvernay.

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

Exploration Expenses

The Company’s exploration expenses were as follows:

(Millions of dollars) 2023 2022 2021

Exploration expenses

Dry holes and previously suspended exploration costs $ 169.8 $ 82.1 $ 17.3

Geological and geophysical 26.1 10.4 11.8

Other exploration 28.0 27.3 21.0

Undeveloped lease amortization 10.9 13.3 18.9

Total exploration expenses

$ 234.8 $ 133.1 $ 69.0

Exploration expenses in 2023 increased by $101.7 million compared to 2022.

Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells in the Gulf of Mexico, which encountered non-commercial hydrocarbons, and the write-off of previously suspended exploration costs for the Cholula-1EXP well in Mexico.

Higher geological and geophysical expenses in 2023 relate to the purchased seismic data for Côte d’Ivoire.

In 2022, dry holes and previously suspended exploration costs primarily relate to expensed costs for the Cutthroat-1 exploration well in block SEAL-M-428 in offshore Brazil and the Tulum-1EXP exploration well in Block 5 in offshore Mexico that did not encounter commercial hydrocarbons.

Other Expenses

Other expenses were $56.9 million in 2023, a decrease of $84.9 million compared to 2022.

Other expenses were lower primarily due to a lower unfavorable contingent consideration adjustment of $7.1 million in 2023 (2022:

$78.3 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note O ).

In addition, there were lower asset retirement adjustments related to non-producing fields of $18.2 million in 2023 (2022:

$35.0 million).

Income taxes were $237.8 million in 2023, a decrease of $179.5 million compared to 2022.

Lower income taxes were primarily the result of lower pre-tax income (see N ote H ).

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments would result from increases in market oil prices relating to future periods whereby the swap contracts provided the Company with a fixed price, and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.

Corporate activities reported a loss of $156.0 million in 2023, a favorable variance of $282.2 million compared to 2022.

The favorable variance was primarily due to no current period losses on derivative instruments in 2023, compared to a loss for the same period in 2022 ($320.4 million) and lower interest expense ($38.6 million), partially offset by lower income tax benefits ($66.0 million) and foreign exchange loss of $10.7 million in 2023 compared to foreign exchange gain of $23.0 million in 2022.

Interest charges are lower in 2023 primarily due to lower overall debt levels as the Company reduced debt by $498.2 million and $647.7 million during 2023 and 2022, respectively.

During 2023 and as of December 31, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding.

Lower income tax benefit was a result of lower pre-tax losses.

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

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 senior unsecured RCF.

The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

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

(Millions of dollars) 2023 2022 2021

Net cash provided by (required by):

Net cash provided by continuing operations activities $ 1,748.8 $ 2,180.2 $ 1,422.2

Net cash required by investing activities

(998.7) (1,109.4) (417.7)

Net cash required by financing activities

(923.7) (1,081.6) (794.5)

Net cash required by discontinued operations

Effect of exchange rate changes on cash and cash equivalents (1.2) (3.9) 0.6

Net (decrease) increase in cash and cash equivalents

$ (174.8) $ (29.2) $ 210.6

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities in 2023 was $431.4 million lower compared to 2022.

The decrease was primarily attributable to lower revenue from production ($661.9 million), higher payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($105.1 million) and timing of working capital settlements ($33.6 million), partially offset by lower realized losses on derivative instruments ($535.2 million).

Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows;

amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition.

Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.

During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows.

As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.

See Note O for further details.

The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in “Financing Activities”) during the two years ended December 31, 2023, and 2022 were $108.9 million and $150.0 million, respectively.

Lower cash interest paid in 2023 was primarily due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.050% senior notes due 2029 (2029 Notes) in the aggregate amount of $498.2 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2023 was $110.7 million lower compared to 2022.

The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million) and lower acquisition capital ($93.0 million), partially offset by higher property additions and dry hole costs ($80.6 million).

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

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

Year Ended December 31,

(Millions of dollars) 2023 2022 2021

Property additions and dry hole costs per cash flow statements 1

$ 1,066.0 $ 985.5 $ 650.2

Geophysical and other exploration expenses 46.0 30.6 26.9

Acquisition of oil properties per the cash flow statements 1

35.6 128.5 20.3

Capital expenditure accrual changes and other (9.5) 38.6 (3.9)

Property additions King's Quay Floating Production System (FPS) per cash flow statements

Total capital expenditures $ 1,138.1 $ 1,183.2 $ 711.2

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.

Total accrual basis capital expenditures are shown below.

Year Ended December 31,

(Millions of dollars) 2023 2022 2021

Capital Expenditures

Exploration and production $ 1,114.0 $ 1,161.5 $ 690.1

Corporate 24.1 21.7 21.1

Total capital expenditures 1,138.1 1,183.2 711.2

Total capital expenditures excluding proved property acquisitions 1,111.0 1,054.7 711.2

Total capital expenditures excluding proved property acquisitions and NCI $ 1,040.8 $ 1,028.8 $ 688.2

Lower capital expenditures in 2023 compared to 2022 were primarily attributable to lower development expenditures at the Khaleesi, Mormont, Samurai field development project, lower spend at the Kodiak and Lucius fields and lower acquisition capital, partially offset by higher exploratory drilling and higher development expenditures at the Dalmatian and St.

Capital expenditures in 2023 primarily relate to development drilling and field development activities in the Eagle Ford Shale ($361.5 million);

development activities in the Gulf of Mexico, primarily related to St.

Malo, Dalmatian, Samurai and Marmalard fields ($310.1 million);

development drilling and field development activities at the Tupper Montney field ($142.0 million);

field development at Terra Nova for the asset life extension project ($44.7 million);

and total exploration costs of $214.3 million.

Exploration costs were primarily for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico and activities at Côte d’Ivoire.

Costs of $169.8 million primarily associated with Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) were expensed to dry hole costs in 2023 as the Company determined there were non-commercial hydrocarbons present.

Cash Required by Financing Activities

Net cash required by financing activities in 2023 decreased by $157.9 million compared to 2022.

In 2023, cash used in financing activities was principally for the redemption of the remaining $248.7 million principal outstanding on its 2025 Notes and the tendering of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes.

In addition, the Company repurchased common shares ($150.0 million, excluding accrued excise tax), paid contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the ‘Cash Provided by Continuing Operating Activities’ section, paid cash dividends to shareholders of $1.10 per share ($171.0 million), and distributed funds to the noncontrolling interest in the Gulf of Mexico ($29.4 million).

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

At December 31, 2023, the Company had approximately $1.1 billion of liquidity consisting of $317.1 million in cash and cash equivalents and $796.2 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $800 million senior unsecured RCF expires in November 2027 and as of December 31, 2023, the Company had no outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF.

Borrowings under the RCF are subject to certain interest rates, please refer to Note F for further details.

At December 31, 2023, the interest rate in effect on borrowings under the facility would have been 7.70%.

At December 31, 2023, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S.

As of December 31, 2023, cash and cash equivalents held outside the U.S.

included U.S dollar equivalents of approximately $148.9 million (2022:

$147.7 million), the majority of which was held in Canada ($105.2 million) and Mexico ($18.1 million).

In addition, approximately $9.6 million and $8.3 million of cash was held in the U.K.

and Spain, 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 United States.

Working Capital

(Millions of dollars) December 31, 2023 December 31, 2022

Working capital

Total current assets $ 752.2 $ 972.3

Total current liabilities 846.5 1,257.8

Net working capital liability

$ (94.3) $ (285.5)

As of December 31, 2023, net working capital had a favorable increase of $191.2 million compared to December 31, 2022.

The favorable increase was primarily attributable to lower other accrued liabilities ($302.8 million) and lower accounts payable ($96.9 million), partially offset by lower accounts receivable ($47.2 million) and a lower cash balance ($174.9 million).

Lower accrued liabilities were primarily due to payments made for contingent consideration obligations from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made in 2023.

Lower accounts payable were primarily due to decreases in unrealized losses on derivative instruments (commodity price swaps and collars), decreases in royalties payable due to lower revenues, payments made for abandonment activities and drilling and completions activities.

Lower unrealized losses on derivative instruments were as a result of no commodity derivative instrument contracts entered into or outstanding during 2023.

Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas liquids and lower pricing received for all crude oil, natural gas liquids and natural gas.

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

Capital Employed

A summary of capital employed as of December 31, 2023 and 2022 follows.

December 31, 2023 December 31, 2022

(Millions of dollars) Amount % Amount %

Capital employed

Long-term debt $ 1,328.4 19.9 % $ 1,822.4 26.7 %

Murphy shareholders' equity 5,362.8 80.1 % 4,994.8 73.3 %

Total capital employed $ 6,691.2 100.0 % $ 6,817.2 100.0 %

As of December 31, 2023, long-term debt decreased by $494.0 million compared to December 31, 2022, as a result of the redemption and early redemption of, in whole or in part, the 2025 Notes, 2027 Notes, 2028 Notes, and 2029 Notes.

The fixed-rate notes had a weighted average maturity of 8.1 years and a weighted average coupon of 6.2%.

Murphy’s shareholders’ equity increased by $368.0 million in 2023 primarily due to net income earned ($661.6 million), partially offset by cash dividends paid ($171.0 million) and shares repurchased ($150.0 million, including excise tax).

A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 69 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 2023, compared to 2022 are discussed below.

Property, plant and equipment, net of depreciation, decreased $2.8 million principally due to DD&A expense ($861.6 million) and divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, substantially offset by capital expenditures in the year and foreign exchange rates applicable for the Canadian assets.

Capital expenditures are discussed above in the ‘Cash Required for Investing Activities’ section.

Murphy had commitments for capital expenditures of approximately $209.8 million at December 31, 2023 (2022:

$282.4 million).

This amount includes $75.1 million for approved expenditures for capital projects relating to non-operated interests in deepwater U.S.

Gulf of Mexico, principally at St.

Malo ($61.7 million), non-operated Canada interests, mainly offshore ($11.6 million), non-operated Lucius ($13.3 million) and non-operated Eagle Ford Shale ($11.8 million).

Operating lease assets decreased $201.2 million principally due to depreciation on these assets.

Deferred Income tax assets decreased by $117.5 million as a result of the decrease in the U.S.

net operating loss carryforward from $2.1 billion at year-end 2022 to $1.7 billion at year-end 2023.

Long term asset retirement obligations increased $86.8 million primarily due to accretion and additions and revisions related to Gulf of Mexico and Eagle Ford Shale operations.

Non-current operating lease liabilities decreased $190.8 million primarily due to 2023 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.

Deferred income tax liabilities increased $61.7 million due to capital related tax deductions.

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.

The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA.

Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.

Also presented below is adjusted EBITDA per barrel of oil equivalent sold.

Management uses Adjusted EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.

Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.

Management uses adjusted net income, EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted net income also excludes 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 and are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

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

Year Ended December 31,

(Millions of dollars, except per barrel of oil equivalents sold) 2022 2021 2020

(Millions of dollars)

2023 2022 2021

Net income attributable to Murphy (GAAP) 1

$ 661.6 $ 965.0 $ (73.7)

Discontinued operations loss 1.5 2.1 1.2

Net income from continuing operations attributable to Murphy

663.1 967.1 (72.5)

Adjustments 2 :

Write-off of previously suspended exploration wells 17.1 22.7 –

Asset retirement obligation losses (gains) 16.9 30.8 (71.8)

Foreign exchange loss (gain)

10.9 (23.0) (1.0)

Mark-to-market loss on contingent consideration

7.1 78.3 63.2

Mark-to-market (gain) loss on derivative instruments

– (214.7) 112.1

(Gain) on sale of assets – (14.5) –

Early redemption of debt cost – 10.3 43.9

Impairment of assets – – 196.3

Tax benefits on investments in foreign areas – – (8.9)

Charges related to Kings Quay transaction – – 4.9

Unutilized rig charges – – 8.7

Total adjustments, before taxes

52.0 (110.1) 347.4

Income tax (benefit) expense related to adjustments (6.4) 23.8 (75.2)

Total adjustments after taxes 45.6 (86.3) 272.2

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 708.7 $ 880.8 $ 199.7

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

$ 4.23 $ 6.14 $ ( 0.47 )

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 4.52 $ 5.59 $ 1.29

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

2 Certain prior-period amounts have been reclassified to conform to the current period presentation.

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

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

Year Ended December 31,

(Millions of dollars)

2023 2022 2021

Net (loss) income attributable to Murphy (GAAP) 1

Income tax expense (benefit) 309.5 (5.9) (293.7)

$ 661.6 $ 965.0 $ (73.7)

Income tax expense 195.9 309.5 (5.9)

Interest expense, net 112.4 150.8 221.8

Depreciation, depletion and amortization expense 2

836.7 748.2 760.6

EBITDA attributable to Murphy (Non-GAAP) 1,806.6 2,173.5 902.8

Mark-to-market (gain) loss on derivative instruments (214.7) 112.1 69.3

Mark-to-market loss (gain) on contingent consideration 78.3 63.2 (13.8)

Foreign exchange (gain) loss (23.0) (1.0) 0.7

Loss (gain) on sale of assets ¹ (14.5) — —

Accretion of asset retirement obligations 2

Write-off of previously suspended exploration wells 22.7 — —

Asset retirement obligation losses (gains) 30.8 (71.8) (2.8)

41.0 40.9 41.1

Write-off of previously suspended exploration well 17.1 22.7 –

Asset retirement obligation loss (gain)

16.9 30.8 (71.8)

Foreign exchange loss (gain)

10.8 (23.0) (1.0)

Mark-to-market loss gain on contingent consideration

7.1 78.3 63.2

Mark-to-market (gain) loss on derivative instruments

– (214.7) 112.1

Discontinued operations loss

Gain on sale of assets 2

Impairment of assets 2

— 196.3 1,072.5

Unutilized rig charges – – 8.7

Restructuring expenses — — 50.0

Inventory loss — — 8.3

Insurance Proceeds — — (1.7)

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,901.0 $ 2,096.1 $ 1,252.6

Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 60,837 57,476 60,189

Adjusted EBITDA per barrel of oil equivalents sold $ 34.45 $ 21.79 $ 15.07

1 Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDA exclude the portion attributable to the non-controlling interest.

Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2022, are presented by segment.

More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.

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

2 Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDA exclude the portion attributable to the noncontrolling interest.

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

A summary of Net income (loss) is presented in the following table.

( Millions of dollars )

2022 2021 2020

Exploration and production – continuing operations

United States $ 1,521.9 $ 766.3 $ (1,014.3)

Canada 134.2 (16.1) (35.0)

Other International (77.0) (33.5) (85.6)

Total exploration and production – continuing operations 1,579.1 716.7 (1,134.9)

Corporate and other (438.3) (668.0) (120.3)

Income (loss) from continuing operations 1,140.8 48.7 (1,255.2)

(Loss) income from discontinued operations (2.1) (1.2) (7.2)

Net income (loss) including noncontrolling interest 1,138.7 47.5 (1,262.4)

Net income (loss) attributable to noncontrolling interest 173.7 121.2 (113.7)

Net income (loss) attributable to Murphy $ 965.0 $ (73.7) $ (1,148.7)

A summary of oil and natural gas revenues is presented in the following table.

( Millions of dollars )

2022 2021 2020

United States Oil and natural gas liquids $ 3,210.3 $ 2,199.7 $ 1,335.8

Natural gas 225.2 121.7 69.4

Canada Oil and natural gas liquids 267.5 228.9 174.0

Natural gas 312.6 245.9 170.6

Other Oil 22.8 4.9 1.8

Total oil and natural gas revenues $ 4,038.4 $ 2,801.1 $ 1,751.6

Exploration and Production

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

The results of operations in this section include amounts attributable to a noncontrolling interest in MP GOM (a subsidiary of Murphy Expro USA, operating and developing properties in the Gulf of Mexico) and exclude discontinued operations, unless otherwise noted.

Exploration and production (E&P) from continuing operations recorded earnings of $1,579.1 million in 2022 compared to earnings of $716.7 million million in 2021.

Results were favorable $862.4 million in 2022 compared to 2021 primarily due to higher oil, natural gas liquid and natural gas prices and volumes, lower impairment charges and lower depreciation, depletion and amortization (DD&A) expense, partially offset by higher lease operating expenses (LOE), other operating expense, exploration expenses, transportation, gathering and processing, severance and ad valorem taxes and income tax charges.

See below for further details.

E&P crude oil price realizations averaged $94.89 per barrel in 2022 compared to $66.80 per barrel in 2021, an increase of 42% year over year.

natural gas realized price per thousand cubic feet (MCF) averaged $6.68 in the current year compared to $3.71 per MCF in 2021, an increase of 80% year over year.

Canada natural gas realized price per MCF averaged U.S.

$2.76 in 2022compared to U.S.

$2.43 per MCF in 2021, an increase of 14% year over year.

E&P oil and natural gas LOE and severance and ad valorem taxes (production costs), on a per-unit basis, were $11.55 in 2022 (2021:

The increase in per-unit production costs in 2022 was primarily attributable to cost increases from inflationary pressures related to the onshore business and higher production from the Khaleesi and Mormont assets.

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, 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 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 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 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 10.

Climate Change and Emissions

The world’s population and standard of living is 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 core elements.

The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information.

Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2023 Sustainability Report issued on August 2, 2023, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2023, many countries worldwide continued to experience a rise in inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

In the U.S., inflation continued as a result of ongoing supply constraints and increasing demand for goods and services as countries continue their recovery from the COVID-19 pandemic.

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and 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+ 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 commitments and therefore is partly protected from the increasing 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

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity