Item 5. Market for Registrant’s Common Equity
Item 5. 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.
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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued
SHAREHOLDER RETURN PERFORMANCE PRESENTATION
The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2018 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group. 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 Kosmos Energy Ltd. Range Resources Corporation
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. 1
2018 2019 2020 2021 2022 2023
Murphy Oil Corporation 100 119 56 125 210 214
Peer Group 100 108 74 147 233 220
S&P 500 Index 100 131 156 200 164 207
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.
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Item 6. RESERVED
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 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.
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. 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.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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’s Net income (loss) by type of business and geographic segment is presented below.
( Millions of dollars )
2023 2022 2021
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. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
E&P Continuing Operations: 2023 vs 2022
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.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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
72.2 181.7 –
Other income
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.
Pricing
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
Other 2
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.
2 U.S. dollar equivalent.
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Item 7. 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
Oil and NGLs
WTI ($/BBL) $ 77.62 $ 94.23 $ 67.91
Natural gas
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.
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Item 7. 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.
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Item 7. 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
Other - Oil
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
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.
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Item 7. 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.
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Item 7. 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
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: 2023 vs 2022
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.
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Item 7. 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.
Cash Flows
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
– (14.5) –
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).
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Item 7. 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
– – 17.7
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. Malo fields. 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).
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Liquidity
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.
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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.
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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, 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)
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.
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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
$ 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
Accretion of asset retirement obligations 2
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
1.5 2.1 1.2
Gain on sale of assets 2
– (14.5) –
Impairment of assets 2
– – 196.3
Unutilized rig charges – – 8.7
Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,901.0 $ 2,096.1 $ 1,252.6
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.
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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, 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
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