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Item 2. Management’s Discussion and Analysis

2024-05-02 compared with 2023-11-02 · 3 added, 463 removed, 24 unchanged (95% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended September 30, 2023 included under Item 1.

Financial Statements of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2022.

Murphy Oil Corporation is a global oil and natural 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.

Our production in the U.S.

is primarily from fields in the Gulf of Mexico and in the Eagle Ford Shale area of South Texas.

In Canada, we produce from the Tupper Montney and Kaybob Duvernay fields in British Columbia and Alberta, and we produce from the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.

Significant Company financial and operational highlights during the third quarter of 2023 were as follows:

• Redeemed the Company’s remaining $248.7 million principal amount outstanding of the 2025 Notes.

• Repurchased shares of our Common Stock under the share repurchase program for $75.8 million, including excise taxes, commissions and fees.

The Company’s total shares of Common Stock outstanding reduced by 1.7 million shares to 154.5 million shares.

• Closed the sale of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets for net cash proceeds of $103 million (C$139 million).

• Production during the quarter was 208,200 barrels of oil equivalent per day (including NCI).

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended September 30, 2023 was $278.2 million, a decrease of $296.3 million compared to the same period in 2022.

Lower net income from continuing operations was largely driven by lower revenues and other income ($343.8 million) and higher other operating expenses ($31.5 million), partially offset by lower income tax expense ($81.3 million).

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

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

Higher 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 three months ended September 30, 2023, total hydrocarbon production was 208,200 barrels of oil equivalent per day, an increase of 6% compared to the third quarter of 2022.

The increase was principally due to higher production from the Gulf of Mexico primarily attributable to Samurai field production starting since the third quarter of 2022, as well as higher production from Canada Onshore, related primarily to new well production at Tupper Montney.

For the nine months ended September 30, 2023, the Company’s net income from continuing operations was $584.7 million, a decrease of $335.3 million compared to the same period of 2022.

Lower net income from continuing operations was largely driven by lower revenues and other income ($341.5 million), higher lease operating expenses ($104.8 million) and higher exploration expenses ($80.3 million), partially offset by lower other operating expense ($94.4 million) and lower income tax expense ($80.8 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 related to higher sales volumes as well as additional costs for workover and maintenance activities at the Gulf of Mexico operations.

Higher exploration costs were the result of dry hole expense for the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa, 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 collars 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Overview (Continued)

For the nine months ended September 30, 2023, total hydrocarbon production was 192,984 barrels of oil equivalent per day, an increase of 11% compared to the same period in 2022.

The increase was principally due to higher production in the Gulf of Mexico from the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore primarily due to new wells at Tupper Montney.

Results of Operations

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

Income (Loss)

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2023 2022 2023 2022

Exploration and production

United States $ 310.3 $ 481.5 $ 705.2 $ 1,225.9

Canada 10.5 41.4 34.9 111.3

Other (12.5) (5.8) (50.0) (53.5)

Total exploration and production

308.3 517.1 690.1 1,283.7

Corporate and other (30.1) 57.4 (105.4) (363.7)

Income from continuing operations 278.2 574.5 584.7 920.0

Discontinued operations ¹ (0.4) (0.4) (0.7) (1.9)

Net income including noncontrolling interest 277.8 574.1 584.0 918.1

Net income attributable to noncontrolling interest

22.5 45.7 38.7 152.5

Net income attributable to Murphy $ 255.3 $ 528.4 $ 545.3 $ 765.6

1 The Company has presented its former U.K.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

E&P Continuing Operations

The following are summarized income statements for our Exploration and Production (E&P) continuing operations:

(Millions of dollars) Three Months Ended

September 30, Nine Months Ended

September 30,

2023 2022 2023 2022

Revenues and other income

Revenue from production

$ 945.9 $ 1,120.9 $ 2,542.0 $ 3,101.7

Sales of purchased natural gas

7.9 45.5 64.6 132.3

2.6 21.8 6.0 26.0

Total revenues and other income

956.4 1,188.2 2,612.6 3,260.0

Cost and Expenses

Lease operating expenses 193.4 198.7 587.6 482.8

Severance and ad valorem taxes 10.9 15.2 35.1 47.4

Transportation, gathering and processing 61.5 55.4 175.3 152.2

Costs of purchased natural gas 5.5 43.7 47.4 125.3

Depreciation, depletion and amortization 234.7 211.2 640.4 564.7

Accretion of asset retirement obligations 11.7 11.2 34.1 34.7

Total exploration expenses 26.4 9.5 152.5 72.2

Selling and general expenses 10.7 9.8 25.0 34.7

Other 7.8 (23.4) 29.0 117.9

Results of operations before taxes 393.8 656.9 886.2 1,628.1

Income tax provisions

85.5 139.8 196.1 344.4

Results of operations (excluding Corporate segment) 1

$ 308.3 $ 517.1 $ 690.1 $ 1,283.7

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

The following table contains the weighted average sales prices for the three-month and nine-month periods ended September 30, 2023 and 2022.

Three Months Ended

September 30, Nine Months Ended

September 30,

(Weighted average sales prices) 2023 2022 2023 2022

Crude oil and condensate – dollars per barrel

United States - Onshore

$ 81.19 $ 94.33 $ 76.40 $ 99.92

United States - Gulf of Mexico 1

82.94 92.96 76.73 99.04

Canada - Onshore 2

76.33 82.25 73.01 92.31

Canada - Offshore 2

94.85 111.76 84.13 112.93

77.19 117.18 82.87 92.91

Natural gas liquids – dollars per barrel

United States - Onshore 20.52 34.33 19.76 36.83

United States - Gulf of Mexico 1

20.16 36.56 22.01 39.99

Canada - Onshore 2

37.72 54.40 39.08 57.53

Natural gas – dollars per thousand cubic feet

United States - Onshore 2.32 7.62 2.24 6.49

United States - Gulf of Mexico 1

2.84 8.68 2.82 7.23

Canada - Onshore 2

1.93 2.75 2.07 2.70

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

dollar equivalent.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

The following table contains benchmark prices relevant to the Company for the three-month and nine-month periods ended September 30, 2023 and 2022.

Three Months Ended

September 30, Nine Months Ended

September 30,

(Average price for the period) 2023 2022 2023 2022

WTI ($/BBL) $ 82.26 $ 91.55 $ 77.39 $ 98.08

NYMEX ($/MMBTU) 2.58 7.96 2.46 6.65

AECO (C$/MCF)

2.60 4.16 2.75 5.38

Production Volumes

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2023 and 2022.

For further discussion on volumes, please see Revenues from Production section on page 26 .

Three Months Ended

September 30, Nine Months Ended

September 30,

(Barrels per day unless otherwise noted) 2023 2022 2023 2022

Net crude oil and condensate

United States - Onshore

27,772 28,522 24,674 25,082

United States - Gulf of Mexico 1

74,843 68,315 74,185 62,380

Canada - Onshore

2,935 3,891 3,104 4,228

Canada - Offshore

2,956 2,171 2,778 2,869

Other 262 487 247 716

Total net crude oil and condensate

108,768 103,386 104,988 95,275

Net natural gas liquids

United States - Onshore

5,272 5,782 4,590 5,268

United States - Gulf of Mexico 1

5,882 4,780 6,170 4,411

Canada - Onshore

732 986 705 942

Total net natural gas liquids

11,886 11,548 11,465 10,621

Net natural gas – thousands of cubic feet per day

United States - Onshore

28,312 30,054 25,571 29,032

United States - Gulf of Mexico 1

70,240 65,319 71,764 61,727

Canada - Onshore

426,725 392,483 361,852 313,422

Total net natural gas

525,277 487,856 459,187 404,181

Total net hydrocarbons - including NCI 2,3

208,200 196,243 192,984 173,260

Noncontrolling interest

Net crude oil and condensate – barrels per day (5,989) (7,125) (6,181) (7,735)

Net natural gas liquids – barrels per day (191) (264) (209) (290)

Net natural gas – thousands of cubic feet per day (1,887) (2,202) (1,996) (2,628)

Total noncontrolling interest 2,3

(6,495) (7,756) (6,723) (8,463)

Total net hydrocarbons - excluding NCI 2,3

201,705 188,487 186,261 164,797

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 (CONTINUED)

Results of Operations (Continued)

The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment, unless otherwise noted.

Revenues from Production

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2023 2022 2023 2022

Revenues from production

United States

$ 821.5 $ 952.3 $ 2,197.3 $ 2,634.0

121.0 163.7 337.6 449.2

3.4 4.9 7.1 18.5

Total revenues from production

$ 945.9 $ 1,120.9 $ 2,542.0 $ 3,101.7

Revenue from production for the three months ended September 30, 2023 decreased by $175.0 million compared to the same period in 2022.

E&P revenue was lower primarily due to lower realized prices, partially offset by higher sales volumes from the Gulf of Mexico.

Higher sales volumes at the Gulf of Mexico were primarily related to production starting at the Samurai field during the fourth quarter of 2022.

Lower revenue from Canadian E&P was due to lower pricing during the third quarter of 2023 and lower sales volumes at Kaybob Duvernay, partially offset by higher sales volumes at Tupper Montney.

Lower sales volumes at Kaybob Duvernay resulted from natural declines.

Higher sales volumes at Tupper Montney were primarily due to five new wells coming into production during the third quarter of 2023, better well performance and lower royalty rates.

Revenue from production for the nine months ended September 30, 2023 decreased by $559.7 million compared to the same period in 2022.

Lower revenue from U.S.

E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells from the Khaleesi, Mormont, Samurai field development project.

Lower revenue 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 natural declines.

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

Sales of purchased natural gas are largely offset with costs to purchase natural gas.

Natural gas is purchased to provide operational flexibility and cost mitigation for transportation commitments.

Other Income for the three and nine months ended September 30, 2023 decreased by $19.2 million and $20.0 million, respectively, compared to the same periods in 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 (CONTINUED)

Results of Operations (Continued)

Lease Operating and Transportation, Gathering and Processing Expenses

The Company’s total lease operating expenses and transportation, gathering and processing expenses by country were as follows:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2023 2022 2023 2022

Lease operating expenses

United States $ 153.2 $ 158.8 $ 472.4 $ 368.2

Canada 39.5 39.6 113.8 113.4

Other 0.7 0.3 1.4 1.2

Total lease operating expenses

$ 193.4 $ 198.7 $ 587.6 $ 482.8

Transportation, gathering and processing

United States 41.9 38.5 119.1 100.0

Canada 19.6 16.9 56.2 52.2

Total transportation, gathering and processing

$ 61.5 $ 55.4 $ 175.3 $ 152.2

Lease operating expenses for the three months ended September 30, 2023 decreased by $5.3 million compared to the same period in 2022.

Lower lease operating expenses from the Gulf of Mexico operations were due to the timing of liftings at Cascade/Chinook fields in the third quarter of 2023, lower repairs and maintenance activities, and lower costs at Dalmatian field due to downtime for operational issues, partially offset by increased costs for higher sales volumes at the Samurai field.

Lease operating expenses from Canada were consistent with the prior period.

Lease operating expenses and transportation, gathering and processing expenses for the nine months ended September 30, 2023 increased by $104.8 million and $23.1 million, respectively, compared to the same period in 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

Depreciation, depletion and amortization expense (DD&A) for the three and nine months ended September 30, 2023 increased by $23.5 million and $75.7 million, respectively, compared to the same periods in 2022.

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

Exploration Expenses

The Company’s exploration expenses were as follows:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2023 2022 2023 2022

Exploration expenses

Dry holes and previously suspended exploration costs $ 11.3 $ 1.1 $ 107.8 $ 35.2

Geological and geophysical 4.3 1.6 15.6 5.3

Other exploration 8.0 4.1 20.9 21.0

Undeveloped lease amortization 2.8 2.7 8.2 10.7

Total exploration expenses

$ 26.4 $ 9.5 $ 152.5 $ 72.2

Exploration expenses for three months ended September 30, 2023 increased by $16.9 million compared to the same period in 2022.

Higher dry holes and previously suspended exploration costs primarily relate to the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico, which finished during the third quarter of 2023.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Exploration expenses for the nine months ended September 30, 2023 increased by $80.3 million compared to the same period in 2022.

Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) exploration well 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.

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.

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

Other Expenses

Other expenses for the three months ended September 30, 2023 increased by $31.2 million compared to the same period in 2022.

Other expense increased primarily due to favorable contingent consideration adjustment recorded in 2022 ($31.4 million) as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L) .

Other expenses for the nine months ended September 30, 2023 decreased by $88.9 million compared to the same period in 2022.

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

$98.5 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L) .

Income taxes for the three and nine months ended September 30, 2023 decreased by $54.3 million and $148.3 million, respectively, compared to the same periods in 2022.

Lower income taxes were primarily the result of lower pre-tax income.

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 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 $30.1 million in the third quarter of 2023, an unfavorable variance of $87.5 million compared to the same period of 2022.

The unfavorable variance was principally due to no current period gains or losses on derivative instruments in the third quarter of 2023 compared to a gain for the same period in 2022 of $115.2 million.

During the third quarter of 2023 and as of September 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding.

Corporate activities also had favorable variances for lower interest expense resulting from overall lower debt levels ($7.6 million) and lower income tax expense ($27.0 million) partially offset by lower foreign exchange gains ($12.4 million).

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

Corporate activities reported a loss of $105.4 million for the nine months ended September 30, 2023, a favorable variance of $258.3 million compared to the same period of 2022.

The favorable variance was primarily due to no current period losses on derivative instruments for the nine months ended September 30, 2023, compared to a loss for the same period in 2022 ($308.7 million) and lower interest expense ($27.5 million), partially offset by lower income tax benefits ($67.5 million) and higher foreign exchange losses ($28.3 million).

Interest charges are lower for the nine months ended September 30, 2023, primarily due to lower overall debt levels as the Company reduced debt by $647.7 million and $248.7 million during 2022 and 2023, respectively.

During the nine months ended September 30, 2023 and as of September 30, 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 (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:

Nine Months Ended

September 30,

(Thousands of dollars) 2023 2022

Net cash provided by (required by):

Net cash provided by continuing operations activities $ 1,205.7 $ 1,678.7

Net cash required by investing activities

(822.2) (928.6)

Net cash required by financing activities

(547.4) (785.6)

Net cash required by discontinued operations

Effect of exchange rate changes on cash and cash equivalents (0.4) (5.2)

Net increase (decrease) in cash and cash equivalents

$ (164.2) $ (55.2)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the nine months ended September 30, 2023 was $473.0 million lower compared to the same period in 2022.

The decrease was primarily attributable to lower revenue from production ($559.8 million), payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($104.8 million) and timing of working capital settlements ($82.9 million), partially offset by lower realized losses on derivative instruments ($447.4 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 the nine months ended September 30, 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.

Cash Required by Investing Activities

Net cash required by investing activities for the nine months ended September 30, 2023 was $106.4 million lower compared to the same period in 2022.

The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets ( $102.9 million) and lower acquisition capital ($102.8 million), partially offset by higher p roperty additions and dry hole costs ($101.4 million) .

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (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.

Nine Months Ended

September 30,

(Millions of dollars) 2023 2022

Property additions and dry hole costs per cash flow statements $ 902.3 $ 800.9

Acquisition of oil and gas properties 22.8 125.6

Geophysical and other exploration expenses 30.1 20.4

Capital expenditure accrual changes and other (69.5) (28.9)

Total capital expenditures $ 885.7 $ 918.0

Total accrual basis capital expenditures are shown below.

Nine Months Ended

September 30,

(Millions of dollars) 2023 2022

Capital Expenditures

Exploration and production $ 870.3 $ 904.1

Corporate 15.4 13.9

Total capital expenditures $ 885.7 $ 918.0

Lower capital expenditures in the E&P business in nine months ended September 30, 2023 compared to the same period of 2022 was primarily attributable to lower development expenditures at the Khaleesi, Mormont, Samurai field development project and lower acquisition capital, partially offset by higher exploratory drilling.

Capital expenditures in 2023 primarily relate to development drilling and field development activities at Eagle Ford Shale assets ($315.2 million), development drilling and field development activities at Tupper Montney field ($118.7 million), development activities in the Gulf of Mexico, primarily related to Dalmatian, Samurai and St.

Malo fields ($193.3 million), field development at Terra Nova for the asset life extension project ($39.5 million), and total exploration costs of $172.0 million for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico.

Costs of $107.8 million associated with Chinook #7 (Walker Ridge 425) were expensed to dry hole costs in the second and third quarters of 2023 as the Company determined there were non-commercial hydrocarbons present.

In the first quarter of 2023, drilling of the Oso #1 (Atwater Valley 138) well was temporarily suspended prior to reaching the objective.

The Company plans to return to the well in the fourth quarter of 2023.

For the nine months ended September 30, 2023, total capital expenditures also included acquisition-related capital of $39.8 million, which consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition and seismic costs for Côte d’Ivoire in offshore Africa.

Cash Required by Financing Activities

Net cash required by financing activities for the nine months ended September 30, 2023 decreased by $238.2 million compared to the same period in 2022.

In 2023, the cash used in financing activities was principally for the redemption and early retirement of the 2025 Notes ($248.7 million), repurchase of common shares ($75.0 million, excluding accrued excise tax), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section, cash dividends to shareholders of $0.83 per share ($128.7 million) and distributions to the noncontrolling interest in the Gulf of Mexico ($20.1 million).

At September 30, 2023, the Company had approximately $1.1 billion of liquidity consisting of $327.8 million in cash and cash equivalents and $795.9 million available on its committed RCF.

The Company had no outstanding

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (Continued)

borrowings under the RCF and $4.1 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

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

As of September 30, 2023, cash and cash equivalents held outside the U.S.

included U.S.

dollar equivalents of approximately $124.4 million, the majority of which was held in Canada ($76.8 million), Mexico ($19.1 million) and the U.K.

($11.7 million).

In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S.

in future periods.

Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

Working Capital

(Millions of dollars) September 30, 2023 December 31, 2022

Working capital

Total current assets $ 887.0 $ 972.3

Total current liabilities 892.4 1,257.8

Net working capital liability

$ (5.4) $ (285.5)

As of September 30, 2023, net working capital had a favorable increase of $280.1 million compared to December 31, 2022.The favorable increase was primarily attributable to lower other accrued liabilities ($306.1 million) and lower accounts payable ($93.8 million), partially offset by higher accounts receivable ($69.5 million), higher operating lease liabilities ($25.5 million) and a lower cash balance ($164.2 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 during the nine months ended September 30, 2023.

Lower accounts payable was primarily due to payments made for drilling and completions activities, partially offset by the decrease in unrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts entered into or outstanding during 2023.

Higher current operating lease liabilities were associated with scheduled rate increases for a drilling vessel resulting in additional amounts being reclassified from long-term to current operating lease liabilities.

Capital Employed

A summary of capital employed at September 30, 2023 and December 31, 2022 follows.

September 30, 2023 December 31, 2022

(Millions of dollars) Amount % Amount %

Capital employed

Long-term debt $ 1,576.3 22.8 % $ 1,822.4 26.7 %

Murphy shareholders' equity 5,340.0 77.2 % 4,994.8 73.3 %

Total capital employed $ 6,916.3 100.0 % $ 6,817.2 100.0 %

At September 30, 2023, long-term debt of $1,576.3 million had decreased by $246.1 million compared to December 31, 2022, primarily as a result of the redemption and early retirement of the 2025 Notes and normal debt issuance cost amortization.

The total of the fixed-rate notes had a weighted average maturity of 7.8 years and a weighted average coupon of 6.2%.

Murphy shareholders’ equity increased by $345.2 million in 2023 primarily due to net income earned ($545.3 million), partially offset by cash dividends paid ($128.7 million) and shares repurchased ($75.8 million, including excise tax).

A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of September 30, 2023, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2022.

Accounting Changes and Recent Accounting Pronouncements – see Note B to the Consolidated Financial Statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Other Key Performance Metrics

The Company uses other operational performance and income metrics to review operational performance.

Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA) 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:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars)

2023 2022 2023 2022

Net income attributable to Murphy (GAAP) 1

$ 255.3 $ 528.4 $ 545.3 $ 765.6

Discontinued operations loss 0.4 0.4 0.7 1.9

Net income from continuing operations 255.7 528.8 546.0 767.5

Adjustments 2 :

Write-off of previously suspended exploration wells — — 17.1 —

Foreign exchange (gain) (8.6) (20.7) (0.3) (28.7)

Mark-to-market (gain) loss on contingent consideration — (31.3) 7.1 98.5

Mark-to-market (gain) on derivative instruments — (239.0) — (138.7)

(Gain) on sale of assets — (15.2) — (15.2)

Early redemption of debt cost — 2.4 — 6.8

Total adjustments, before taxes

(8.6) (303.8) 23.9 (77.3)

Income tax (benefit) expense related to adjustments 2.2 64.7 (1.4) 17.3

Total adjustments after taxes (6.4) (239.1) 22.5 (60.0)

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 249.3 $ 289.7 $ 568.5 $ 707.5

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 (CONTINUED)

Other Key Performance Metrics (Continued)

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2023 2022 2023 2022

Net income attributable to Murphy (GAAP) 1

$ 255.3 $ 528.4 $ 545.3 $ 765.6

Income tax expense 78.1 159.5 166.8 247.6

Interest expense, net 30.0 37.4 88.7 116.1

Depreciation, depletion and amortization expense 2

231.5 207.7 630.8 552.5

EBITDA attributable to Murphy (Non-GAAP) 594.9 933.0 1,431.6 1,681.8

Write-off of previously suspended exploration well — — 17.1 —

Accretion of asset retirement obligations 2

10.4 10.0 30.4 30.7

Foreign exchange (gain) (8.6) (20.7) (0.3) (28.7)

Mark-to-market (gain) loss on contingent consideration — (31.4) 7.1 98.5

Discontinued operations loss 0.4 0.4 0.7 1.9

Mark-to-market (gain) on derivative instruments – (239.1) – (138.7)

Gain on sale of assets 2

— (15.2) – (15.2)

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 597.1 $ 637.1 $ 1,486.6 $ 1,630.3

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile a nd is aff ected by the levels of supply and demand for energy.

As discussed in the Results of Operations section discussing revenues, on page 26 , lower average crude oil price during the third quarter of 2023 directly impacts the Company’s product revenue from sales.

As of close on October 31, 2023, forward price curves for existing forward contracts for the remainder of 2023 and 2024 are shown in the table below:

NYMEX ($/MMBTU)

AECO (US$ Equivalent/MCF)

Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company is observing higher costs for goods and services used in E&P operations.

Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing.

Lower prices, should they occur, will result in lower profits and operating cash flows.

For the fourth quarter of 2023, production is expected to average between 181.5 and 189.5 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

The Company’s capital expenditure spend for 2023 is expected to be between $950.0 million and $1,025.0 million, excluding noncontrolling interest.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.

Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

The Company will primarily fund its capital program in 2023 using operating cash flow and available cash.

If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction.

Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022.

In addition, subsequent to the third quarter of 2023, the Company’s Board of Directors 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, and has $ 525 million remaining available to repurchase.

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note E ).

As of October 31, 2023, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

(MMcf/d) Price/Mcf Remaining Period

Area Commodity Type Start Date End Date

Canada Natural Gas Fixed price forward sales 250 C$2.35 10/1/2023 12/31/2023

Canada Natural Gas Fixed price forward sales 25 US$1.98 10/1/2023 10/31/2024

Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024

Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

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

Forward-Looking Statements

5 unchanged sentences

macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices;

geopolitical concerns;

increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves;

8 unchanged sentences

or adverse developments in the U.S.

or global capital markets, credit markets, banking system or economies in general.

or global capital markets, credit markets, banking system or economies in general, including inflation.

For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S.

6 unchanged sentences

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-Q

Item 2. Management’s Discussion and Analysis