UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q  

(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2023

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-200		77024
Houston,	Texas	(Zip Code)
(Address of principal executive offices)
(281)		675-9000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $1.00 Par Value	MUR	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes    ☐ No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

Number of shares of Common Stock, $1.00 par value, outstanding at October 31, 2023 was 154,473,141.

MURPHY OIL CORPORATION

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1.  Financial Statements
Consolidated Balance Sheets	2
Consolidated Statements of Operations	3
Consolidated Statements of Comprehensive Income	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Stockholders’ Equity	6
Notes to Consolidated Financial Statements	7
Note A – Basis of Presentation	7
Note B – New Accounting Principles and Recent Accounting Pronouncements	7
Note C – Revenue from Contracts with Customers	7
Note D – Property, Plant and Equipment	10
Note E – Financing Arrangements and Debt	11
Note F – Other Financial Information	11
Note G – Asset Retirement Obligations	12
Note H – Employee and Retiree Benefit Plans	13
Note I – Incentive Plans	13
Note J – Earnings Per Share	15
Note K – Income Taxes	15
Note L – Financial Instruments and Risk Management	16
Note M – Accumulated Other Comprehensive Loss	18
Note N – Environmental and Other Contingencies	19
Note O – Common Stock Issued and Outstanding	20
Note P – Business Segments	21
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of               Operations	21
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.  Controls and Procedures	36
Part II – Other Information	37
Item 1.  Legal Proceedings	37
Item 1A.  Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 5. Other Information	37
Item 6.  Exhibits	37
Signature	38

1

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(Thousands of dollars, except share amounts)	September 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	327,769	$	491,963
Accounts receivable, net	460,630		391,152
Inventories	60,435		54,513
Prepaid expenses	38,177		34,697
Total current assets	887,011		972,325
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,837,868 in 2023 and $12,489,970 in 2022	8,218,015		8,228,016
Operating lease assets	792,149		946,406
Deferred income taxes	1,111		117,889
Deferred charges and other assets	44,292		44,316
Total assets	$	9,942,578	$	10,308,952
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	714	$	687
Accounts payable	449,960		543,786
Income taxes payable	24,000		26,544
Other taxes payable	34,335		22,819
Operating lease liabilities	245,884		220,413
Other accrued liabilities	137,500		443,585
Total current liabilities	892,393		1,257,834
Long-term debt, including finance lease obligation	1,576,279		1,822,452
Asset retirement obligations	859,123		817,268
Deferred credits and other liabilities	289,962		304,948
Non-current operating lease liabilities	561,254		742,654
Deferred income taxes	250,768		214,903
Total liabilities	$	4,429,779	$	5,160,059
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	$	–	$	–
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2023 and 195,100,628 shares in 2022	195,101		195,101
Capital in excess of par value	869,132		893,578
Retained earnings	6,472,114		6,055,498
Accumulated other comprehensive loss	(533,940)		(534,686)
Treasury stock	(1,662,376)		(1,614,717)
Murphy Shareholders' Equity	5,340,031		4,994,774
Noncontrolling interest	172,768		154,119
Total equity	5,512,799		5,148,893
Total liabilities and equity	$	9,942,578	$	10,308,952

See Notes to Consolidated Financial Statements, page 7.

2

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars, except per share amounts)	2023		2022		2023		2022
Revenues and other income
Revenue from production	$	945,889	$	1,120,909	$	2,541,956	$	3,101,736
Sales of purchased natural gas	7,877		45,500		64,628		132,285
Total revenue from sales to customers	953,766		1,166,409		2,606,584		3,234,021
Gain (loss) on derivative instruments	–		115,191		–		(308,654)
Gain on sale of assets and other income	5,879		21,825		9,365		32,076
Total revenues and other income	959,645		1,303,425		2,615,949		2,957,443
Costs and expenses
Lease operating expenses	193,402		198,710		587,678		482,887
Severance and ad valorem taxes	10,937		15,140		35,142		47,340
Transportation, gathering and processing	61,518		55,348		175,308		152,219
Costs of purchased natural gas	5,467		43,622		47,393		125,258
Exploration expenses, including undeveloped lease amortization	26,514		9,491		152,489		72,208
Selling and general expenses	30,745		29,348		74,398		90,007
Depreciation, depletion and amortization	237,493		214,521		648,830		574,501
Accretion of asset retirement obligations	11,675		11,286		34,196		34,725
Other operating expense (benefit)	4,385		(27,129)		21,333		115,726
Total costs and expenses	582,136		550,337		1,776,767		1,694,871
Operating income from continuing operations	377,509		753,088		839,182		1,262,572
Other loss
Other income	8,811		18,301		1,044		21,114
Interest expense, net	(29,984)		(37,440)		(88,695)		(116,102)
Total other loss	(21,173)		(19,139)		(87,651)		(94,988)
Income from continuing operations before income taxes	356,336		733,949		751,531		1,167,584
Income tax expense	78,111		159,451		166,813		247,574
Income from continuing operations	278,225		574,498		584,718		920,010
Loss from discontinued operations, net of income taxes	(421)		(422)		(744)		(1,916)
Net income including noncontrolling interest	277,804		574,076		583,974		918,094
Less: Net income attributable to noncontrolling interest	22,462		45,648		38,701		152,445
NET INCOME ATTRIBUTABLE TO MURPHY	$	255,342	$	528,428	$	545,273	$	765,649
INCOME PER COMMON SHARE – BASIC
Continuing operations	$	1.64	$	3.40	$	3.50	$	4.94
Discontinued operations	–		–		–		(0.01)
Net income	$	1.64	$	3.40	$	3.50	$	4.93
INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	1.63	$	3.36	$	3.47	$	4.87
Discontinued operations	–		–		–		(0.01)
Net income	$	1.63	$	3.36	$	3.47	$	4.86
Cash dividends per common share	$	0.275	$	0.250	$	0.827	$	0.575
Average common shares outstanding (thousands)
Basic	155,454		155,446		155,749		155,221
Diluted	156,829		157,336		157,135		157,407

See Notes to Consolidated Financial Statements, page 7.

3

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)	2023		2022		2023		2022
Net income including noncontrolling interest	$	277,804	$	574,076	$	583,974	$	918,094
Other comprehensive (loss) income, net of tax
Net gain (loss) from foreign currency translation	(39,353)		(102,266)		(2,601)		(135,791)
Retirement and postretirement benefit plans	1,196		3,165		3,347		9,674
Other comprehensive (loss) income	(38,157)		(99,101)		746		(126,117)
Comprehensive income (loss) including noncontrolling interest	$	239,647	$	474,975	$	584,720	$	791,977
Less: Comprehensive income attributable to noncontrolling interest	22,462		45,648		38,701		152,445
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	217,185	$	429,327	$	546,019	$	639,532

See Notes to Consolidated Financial Statements, page 7.

4

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
(Thousands of dollars)	2023		2022
Operating Activities
Net income including noncontrolling interest	$	583,974	$	918,094
Adjustments to reconcile net income to net cash provided by continuing operations activities
Loss from discontinued operations	744		1,916
Depreciation, depletion and amortization	648,830		574,501
Unsuccessful exploration well costs and previously suspended exploration costs	107,825		35,224
Amortization of undeveloped leases	8,215		10,651
Accretion of asset retirement obligations	34,196		34,725
Deferred income tax expense	152,104		207,105
Contingent consideration payment	(139,574)		–
Mark to market loss on contingent consideration	7,113		98,451
Mark to market gain on derivative instruments	–		(138,707)
Long-term non-cash compensation	42,502		57,612
Gain from sale of assets	(12)		(18,871)
Net increase in noncash working capital	(142,788)		(59,874)
Other operating activities, net	(97,395)		(42,101)
Net cash provided by continuing operations activities	1,205,734		1,678,726
Investing Activities
Property additions and dry hole costs	(902,295)		(800,868)
Acquisition of oil and natural gas properties	(22,773)		(125,602)
Proceeds from sales of property, plant and equipment	102,913		(2,129)
Net cash required by investing activities	(822,155)		(928,599)
Financing Activities
Borrowings on revolving credit facility	300,000		300,000
Repayment of revolving credit facility	(300,000)		(300,000)
Retirement of debt	(248,675)		(446,032)
Early redemption of debt cost	–		(5,419)
Repurchase of common stock	(75,023)		—
Contingent consideration payment	(60,243)		(81,742)
Cash dividends paid	(128,657)		(89,354)
Distributions to noncontrolling interest	(20,052)		(145,273)
Withholding tax on stock-based incentive awards	(14,232)		(17,338)
Capital lease obligation payments	(457)		(475)
Issue costs of debt facility	(20)		–
Net cash required by financing activities	(547,359)		(785,633)
Net cash required by discontinued operations	–		(14,500)
Effect of exchange rate changes on cash and cash equivalents	(414)		(5,180)
Net decrease in cash and cash equivalents	(164,194)		(55,186)
Cash and cash equivalents at beginning of period	491,963		521,184
Cash and cash equivalents at end of period	$	327,769	$	465,998

See Notes to Consolidated Financial Statements, page 7.

5

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars except number of shares)	2023		2022		2023		2022
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	–	$	–	$	–	$	–
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2023 and 195,100,628 shares at September 30, 2022
Balance at beginning and end of period	195,101		195,101		195,101		195,101
Capital in Excess of Par Value
Balance at beginning of period	861,951		883,368		893,578		926,698
Restricted stock transactions and other	44		(1,956)		(42,371)		(57,760)
Share-based compensation	7,137		6,318		17,925		18,792
Balance at end of period	869,132		887,730		869,132		887,730
Retained Earnings
Balance at beginning of period	6,259,561		5,405,400		6,055,498		5,218,670
Net income attributable to Murphy	255,342		528,428		545,273		765,649
Cash dividends paid	(42,789)		(38,863)		(128,657)		(89,354)
Balance at end of period	6,472,114		5,894,965		6,472,114		5,894,965
Accumulated Other Comprehensive Loss
Balance at beginning of period	(495,783)		(554,727)		(534,686)		(527,711)
Foreign currency translation (loss) gain, net of income taxes	(39,353)		(102,266)		(2,601)		(135,791)
Retirement and postretirement benefit plans, net of income taxes	1,196		3,165		3,347		9,674
Balance at end of period	(533,940)		(653,828)		(533,940)		(653,828)
Treasury Stock
Balance at beginning of period	(1,586,522)		(1,616,340)		(1,614,717)		(1,655,447)
Purchase of treasury shares	(75,773)		–		(75,773)		–
Awarded restricted stock, net of forfeitures	(81)		1,313		28,114		40,420
Balance at end of period – 40,627,487 shares of Common Stock in 2023 and 39,645,345 shares of Common Stock in 2022, at cost	(1,662,376)		(1,615,027)		(1,662,376)		(1,615,027)
Murphy Shareholders’ Equity	5,340,031		4,708,941		5,340,031		4,708,941
Noncontrolling Interest
Balance at beginning of period	154,375		175,428		154,119		163,485
Net income attributable to noncontrolling interest	22,462		45,648		38,701		152,445
Distributions to noncontrolling interest owners	(4,069)		(50,419)		(20,052)		(145,273)
Balance at end of period	172,768		170,657		172,768		170,657
Total Equity	$	5,512,799	$	4,879,598	$	5,512,799	$	4,879,598

See Notes to Consolidated Financial Statements, page 7.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.

Note A – Basis of Presentation

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all accruals necessary to present fairly the Company’s financial position as at September 30, 2023 and December 31, 2022, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2023 and 2022, in conformity with U.S generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2022 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2023 are not necessarily indicative of future results.

In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG) acquisition, we hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated as Murphy is not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, 2023, our maximum exposure to loss was $3.1 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

None.

Recent Accounting Pronouncements

None affecting the Company.

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids (NGL), and natural gas.

For operated oil and natural gas production where the non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by ASC 810-10-45.

U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.

Canada - In Canada, contracts include long-term floating commodity index priced and natural gas fixed-price forward physical contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load, based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.

		Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)		2023		2022		2023		2022
Net crude oil and condensate revenue
United States	Onshore	$	207,448	$	247,562	$	514,614	$	684,099
	Offshore	568,721		597,242		1,549,872		1,675,389
Canada	Onshore	20,610		29,445		61,868		106,559
	Offshore	22,272		30,030		63,273		97,216
Other		3,442		4,867		7,086		18,503
Total crude oil and condensate revenue		822,493		909,146		2,196,713		2,581,766
Net natural gas liquids revenue
United States	Onshore	9,953		18,288		24,763		53,035
	Offshore	10,908		16,079		37,078		48,151
Canada	Onshore	2,539		4,932		7,519		14,800
Total natural gas liquids revenue		23,400		39,299		69,360		115,986
Net natural gas revenue
United States	Onshore	6,035		21,009		15,623		51,412
	Offshore	18,377		52,143		55,311		121,911
Canada	Onshore	75,584		99,312		204,949		230,661
Total natural gas revenue		99,996		172,464		275,883		403,984
Revenue from production		945,889		1,120,909		2,541,956		3,101,736
Sales of purchased natural gas
United States	Offshore	–		–		–		181
Canada	Onshore	7,877		45,500		64,628		132,104
Total sales of purchased natural gas		7,877		45,500		64,628		132,285
Total revenue from sales to customers		953,766		1,166,409		2,606,584		3,234,021
Gain (loss) on derivative instruments		–		115,191		–		(308,654)
Gain on sale of assets and other income		5,879		21,825		9,365		32,076
Total revenues and other income		$	959,645	$	1,303,425	$	2,615,949	$	2,957,443

Contract Balances and Asset Recognition

As of September 30, 2023, and December 31, 2022, receivables from contracts with customers, net of royalties and associated payables, on the balance sheets, were $248.8 million and $201.1 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as of September 30, 2023.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any costs incurred to obtain a contract with a customer that should be recognized as an asset.

Performance Obligations

The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.

As of September 30, 2023, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:

Current Long-Term Contracts Outstanding at September 30, 2023
Location	Commodity	End Date	Description	Approximate Volumes
U.S.	Natural Gas and NGL	Q1 2030	Deliveries from dedicated acreage in Eagle Ford	As produced
Canada	Natural Gas	Q4 2025	Contracts to sell natural gas at USD index pricing	25 MMCFD
Canada	Natural Gas	Q4 2023	Contracts to sell natural gas at CAD fixed prices	38 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at USD index pricing	31 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at CAD fixed prices	100 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at CAD fixed prices	34 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at USD index fixed prices	15 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at CAD index prices	28 MMCFD
Canada	Natural Gas	Q4 2026	Contracts to sell natural gas at USD index pricing	49 MMCFD
Canada	Natural Gas	Q4 2027	Contracts to sell natural gas at USD index prices	20 MMCFD
Canada	NGL	Q1 2024	Contracts to sell natural gas liquids at various CAD pricing	As produced

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment

Exploratory Wells

Under Financial Accounting Standards Board guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

As of September 30, 2023, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $185.5 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2023 and 2022.

(Thousands of dollars)	2023		2022
Beginning balance at January 1	$	171,860	$	179,481
Additions pending the determination of proved reserves	40,825		22,275
Reclassifications to proved properties based on the   determination of proved reserves	(1,065)		–
Capitalized exploratory well costs charged to expense	(26,143)		(20,295)
Balance at September 30	$	185,477	$	181,461

Capital additions of $40.8 million in 2023 are primarily related to Oso #1 well (Atwater Valley 138) and LDV-4X in Vietnam. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the fourth quarter of 2023. Capitalized well costs charged to dry hole expense of $26.1 million for the nine months ended September 30, 2023 are related to Cholula-1EXP well in Mexico and Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico. The preceding table excludes well costs of $81.7 million incurred and expensed directly to dry hole during the nine months ended September 30, 2023, related to the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.

	September 30,
	2023				2022
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	–	–	–	$	8,851	2	2
One to two years	38,817		1	1	8,489		2	2
Two to three years	2,698		1	1	–		–	–
Three years or more	143,962		4	3	164,121		6	3
	$	185,477	6	5	$	181,461	10	7

Of the $185.5 million of exploratory well costs capitalized more than one year at September 30, 2023, $112.8 million was in Vietnam, $65.3 million was in the U.S., $4.7 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

Impairments

There were no impairments in the nine months ended September 30, 2023 or 2022.

Divestitures

On September 15, 2023, the Company completed the previously announced divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash proceeds of C$139.0 million. No gain or loss was recorded related to this transaction, and the effective date of the transaction was March 1, 2023.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt

As of September 30, 2023, the Company had an $800 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on November 17, 2027. At September 30, 2023, the Company had no outstanding borrowings under the RCF and $4.1 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2023, the interest rate in effect on borrowings under the RCF would have been 7.92%. At September 30, 2023, the Company was in compliance with all covenants related to the RCF.

In September 2023, the Company redeemed the remaining $248.7 million principal amount outstanding of its 5.75% senior notes due 2025 (2025 Notes). The non-cash costs of the debt extinguishment of $0.9 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2023.

The Company irrevocably deposited the repayment amount with a trustee in September 2023. With this deposit, as per the terms of the 2025 Notes indenture, all covenants and conditions were complied with to satisfy and discharge the full indebtedness of the 2025 Notes. The Trustee has been irrevocably instructed to repay all sums outstanding and payable on the Redemption Date in accordance with the Indenture.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2024.

Note F – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

	Nine Months Ended September 30,
(Thousands of dollars)	2023		2022
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) in accounts receivable	$	(69,689)	$	(130,792)
(Increase) decrease in inventories	(6,609)		(410)
(Increase) in prepaid expenses	(3,364)		(8,561)
Increase (decrease) in accounts payable and accrued liabilities ¹	(60,582)		61,139
Increase (decrease) in income taxes payable	(2,544)		18,750
Net increase in noncash working capital	$	(142,788)	$	(59,874)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	12,737	$	16,493
Interest paid, net of amounts capitalized of $10.4 million in 2023 and $13.2 million in 2022	78,169		112,332
Non-cash investing activities:
Asset retirement costs capitalized	$	16,219	$	29,327
Decrease in capital expenditure accrual	75,760		34,853

1 Excludes payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note G – Asset Retirement Obligations

The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the nine-month periods ended September 30, 2023 and 2022 is shown in the following table.

(Thousands of dollars)	September 30, 2023		September 30, 2022
Balance at beginning of year	$	911,653	$	971,893
Accretion	34,196		34,725
Liabilities incurred	16,441		(18,555)
Revisions of previous estimates	(822)		–
Liabilities settled	(89,340)		(28,927)
Changes due to translation of foreign currencies	(340)		(13,592)
Balance at end of period	871,788		945,544
Current portion of liability 1	(12,665)		(96,937)
Noncurrent portion of liability	$	859,123	$	848,607

1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.

The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans meet the requirements of local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2023 and 2022.

	Three Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2023		2022		2023		2022
Service cost	$	1,650	$	2,129	$	132	$	292
Interest cost	8,534		5,163		874		574
Expected return on plan assets	(8,223)		(7,999)		–		–
Estimated defined contribution provision	53		–		–		–
Amortization of prior service cost (credit)	155		582		(133)		(133)
Recognized actuarial loss (gain)	2,407		3,822		(767)		(77)
Total net periodic benefit expense	$	4,576	$	3,697	$	106	$	656
	Nine Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2023		2022		2023		2022
Service cost	$	4,950	$	6,387	$	396	$	876
Interest cost	25,605		15,545		2,622		1,722
Expected return on plan assets	(24,671)		(24,091)		–		–
Estimated defined contribution provision	161		–		–		–
Amortization of prior service cost (credit)	465		1,761		(399)		(399)
Recognized actuarial loss (gain)	7,222		11,466		(2,315)		(232)
Total net periodic benefit expense	$	13,732	$	11,068	$	304	$	1,967

The components of net periodic benefit expense, other than the service cost, are recorded in “Other income” in the Consolidated Statements of Operations.

During the nine-month period ended September 30, 2023, the Company made contributions of $31.5 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2023 for the Company’s defined benefit pension and postretirement plans is anticipated to be $5.5 million.

Note I – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I - Incentive Plans (Continued)

The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of five million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.

During the nine months ended September 30, 2023, the Committee granted the following awards from the 2020 Long-Term Plan:

Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Performance Based RSUs 1	409,160	January 31, 2023	$	60.46	Monte Carlo
Time Based RSUs 2	499,220	January 31, 2023	43.27		Average Stock Price
Cash Settled RSUs 3	123,230	January 31, 2023	43.27		Average Stock Price

1 Performance based RSUs are scheduled to vest over a three year performance period.

2 Time based RSUs are generally scheduled to vest over three years from the date of grant.

3 Cash settled RSUs are generally scheduled to vest over three years from the date of grant.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan) and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.

During the nine months ended September 30, 2023, the Committee granted the following awards to Non-Employee Directors:

Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Time Based RSUs 1	56,880	February 1, 2023	$	42.20	Closing Stock Price

1 Non-employee directors time-based RSUs are scheduled to vest in February 2024.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2023.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

	Nine Months Ended September 30,
(Thousands of dollars)	2023		2022
Compensation charged against income before tax benefit	$	42,912	$	43,216
Related income tax benefit recognized in income	7,244		6,872

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note J – Earnings Per Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2023 and 2022. The following table reports the weighted-average shares outstanding used for these computations.

	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2023	2022	2023	2022
Basic method	155,453,897	155,446,201	155,749,486	155,220,945
Dilutive stock options and restricted stock units ¹	1,375,511	1,889,972	1,385,859	2,185,957
Diluted method	156,829,408	157,336,173	157,135,345	157,406,902

1 The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Antidilutive stock options excluded from diluted shares	–		1,316,222		–		163,800
Weighted average price of these options	$	–	$	34.42	$	–	$	49.65

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, 2023 and 2022, the Company’s effective income tax rates were as follows:

	2023	2022
Three months ended September 30,	21.9%	21.7%
Nine months ended September 30,	22.2%	21.2%

The effective tax rate for the three-month period ended September 30, 2023, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the three-month period ended September 30, 2022, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the nine-month period ended September 30, 2023, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the nine-month period ended September 30, 2022, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were mostly offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company has paid amounts into escrow, and may from time to time pay more amounts into escrow, in order to continue tax disputes with the relevant taxing authorities. As of September 30, 2023, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2016. Following the sale in 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Note L – Financial Instruments and Risk Management

Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. 

Commodity Price Risks

During the third quarter of 2023, the Company did not have any crude oil derivative contracts.

During the third quarter of 2022, the Company had crude oil swaps and collar contracts. Under the swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also matured monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts required payments by the Company if the NYMEX average closing price was above the ceiling price or payments to the Company if the NYMEX average closing price was below the floor price.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at September 30, 2023 and 2022.

For the three-month and nine-month periods ended September 30, 2023 and 2022, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

		Gain (Loss)				Gain (Loss)
(Thousands of dollars)	Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
Type of Derivative Contract		2023		2022		2023		2022
Commodity swaps	Gain (loss) on derivative instruments	$	–	$	50,089	$	–	$	(152,822)
Commodity collars	Gain (loss) on derivative instruments	–		65,102		–		(155,832)

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2023 and December 31, 2022, are presented in the following table.

	September 30, 2023								December 31, 2022
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Liabilities:
Nonqualified employee savings plan	$	15,256	$	–	$	–	$	15,256	$	15,135	$	–	$	–	$	15,135
	$	15,256	$	–	$	–	$	15,256	$	15,135	$	–	$	–	$	15,135

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.

As of September 30, 2023, there were no outstanding commodity West Texas Intermediate (WTI) crude oil swaps and collars contracts subject to fair value measurement.

As of December 31, 2022, there were no outstanding commodity WTI crude oil swaps and collars contracts subject to fair value measurement. The liabilities associated with these contracts have been finalized as of December 31, 2022 and were based on realized WTI pricing. The commodity swaps and collars liability as of December 31, 2022 was $19.6 million and $2.3 million, respectively, and recorded as “Accounts payable” in the Consolidated Balance Sheets.

In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG). Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds were exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020; however, the threshold was met in 2021 and 2022. The obligation period related to LLOG revenue-related contingent consideration ended in 2022, with final payments made in the first half of 2023.

In 2018, the Company, through a subsidiary, acquired Gulf of Mexico producing assets from Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A. Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $150 million if certain price and production thresholds were exceeded beginning in 2019 through 2025; and $50 million carry for PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. The price and production thresholds were not exceeded for 2019 and 2020; however, the thresholds were met in 2021 and 2022. As of December 31, 2021, Murphy had completely funded the carried interest. As of December 31, 2022, the $150 million obligation limit was achieved and paid in the first half of 2023.

As at December 31, 2022, the Company’s liabilities with PAI and LLOG were based on realized inputs of volumes and pricing as a result of reaching contractual thresholds or time limitations that ended in 2022. As a result, the related liabilities as at December 31, 2022 of $192.7 million were no longer subject to fair value measurement. The liability remaining was included in “Other accrued liabilities” in the Consolidated Balance Sheets.

As of the end of the second quarter of 2023, the Company had no remaining liabilities relating to prior acquisitions from PAI and LLOG. During the nine months ended September 30, 2023, the Company paid a total of $199.8 million in contingent consideration payments. In the Consolidated Statements of Cash Flows, $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities”.

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 2023 and December 31, 2022.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2023 and December 31, 2022. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

	September 30,				December 31,
	2023				2022
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,576,993	$	1,450,929	$	1,823,139	$	1,668,216

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2022 and September 30, 2023 and the changes during the nine-month period ended September 30, 2023 are presented net of taxes in the following table.

(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Total
Balance at December 31, 2022	$	(418,230)	$	(116,456)	$	(534,686)
Components of other comprehensive income (loss):
Before reclassifications to income	(2,601)		–		(2,601)
Reclassifications to income ¹	–		3,347		3,347
Net other comprehensive income (loss)	(2,601)		3,347		746
Balance at September 30, 2023	$	(420,831)	$	(113,109)	$	(533,940)

1  Reclassifications before taxes of $4,146 thousand are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2023. See Note H for additional information. Related income taxes of $799 thousand are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2023.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.

ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. 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 Greenhouse Gas (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.

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environment legal proceedings likely to exceed this $1.0 million threshold.

There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, the Inflation Reduction Act of 2022 contains provisions that impose fees for excess methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note O – Common Stock Issued and Outstanding

Activity in the number of shares of the Company’s Common Stock issued and outstanding for the nine-month periods ended September 30, 2023 and 2022 is shown below.

(Number of shares outstanding)	September 30, 2023	September 30, 2022
Beginning of period	155,467,319	154,463,050
Stock options exercised 1	520	169,619
Restricted stock awards 1	689,824	822,614
Treasury shares purchased 2	1,684,522	–
End of period	154,473,141	155,455,283

1 Shares issued upon exercise of stock options and award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.

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

On August 4, 2022, the Company’s Board of Directors authorized a share repurchase program of up to $300 million of the Company’s Common Stock. 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 and dependent upon a variety of factors. During the three and nine months ended September 30, 2023, the Company repurchased 1,684,522 shares of its Common Stock under the share repurchase program for $75.8 million, including excise taxes, commissions and fees.

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.

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments

Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on commodity price derivatives), interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.) and U.S. refining and marketing operations as discontinued operations for all periods presented.

	Total Assets at September 30, 2023		Three Months Ended September 30, 2023				Three Months Ended September 30, 2022
(Millions of dollars)			External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States	$	6,925.0	$	823.7	$	310.3	$	973.8	$	481.5
Canada	2,074.7		129.3		10.5		209.6		41.4
Other	226.9		3.4		(12.5)		4.8		(5.8)
Total exploration and production	9,226.6		956.4		308.3		1,188.2		517.1
Corporate	714.9		3.2		(30.1)		115.2		57.4
Continuing operations	9,941.5		959.6		278.2		1,303.4		574.5
Discontinued operations, net of tax	1.1		–		(0.4)		–		(0.4)
Total	$	9,942.6	$	959.6	$	277.8	$	1,303.4	$	574.1
			Nine Months Ended September 30, 2023				Nine Months Ended September 30, 2022
(Millions of dollars)			External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States			$	2,202.2	$	705.2	$	2,659.2	$	1,225.9
Canada			403.3		34.9		582.3		111.3
Other			7.1		(50.0)		18.5		(53.5)
Total exploration and production			2,612.6		690.1		3,260.0		1,283.7
Corporate			3.3		(105.4)		(302.6)		(363.7)
Continuing operations			2,615.9		584.7		2,957.4		920.0
Discontinued operations, net of tax			–		(0.7)		–		(1.9)
Total			$	2,615.9	$	584.0	$	2,957.4	$	918.1

1 Additional detail about the results of oil and natural gas operations is presented in the Exploration and Production Continuing Operations table on page 24 .

21

ITEM 2.  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.

Overview

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.

22

ITEM 2.  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. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 

23

ITEM 2.  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
Other income	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.

Pricing

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
Other 2	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.

2 U.S. dollar equivalent.

24

ITEM 2.  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
Oil and NGLs
WTI ($/BBL)	$	82.26	$	91.55	$	77.39	$	98.08
Natural gas
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.

25

ITEM 2.  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
Canada	121.0		163.7		337.6		449.2
Other	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. U.S. 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

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.

26

ITEM 2.  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.

27

ITEM 2.  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

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

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.

28

ITEM 2.  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.

Cash Flows

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	–		(14.5)
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 property additions and dry hole costs ($101.4 million).

29

ITEM 2.  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).

Liquidity

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

30

ITEM 2.  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.

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ITEM 2.  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.

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ITEM 2.  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).

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Outlook

The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and is affected 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:

	2023	2024
WTI ($/BBL)	81.02	77.93
NYMEX ($/MMBTU)	3.58	3.61
AECO (US$ Equivalent/MCF)	2.22	2.22

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:

			Volumes (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

34

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general. 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. Securities and Exchange Commission (“SEC”) and on page 37 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy, at times, makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were no derivative commodity contracts in place at September 30, 2023.

There were no derivative foreign exchange contracts in place at September 30, 2023.

ITEM 4.  CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During the quarter ended September 30, 2023, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

36

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy and its subsidiaries are engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in the Company’s 2022 Form 10-K filed on February 27, 2023. The Company has not identified any additional risk factors not previously disclosed in its 2022 Form 10-K report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchase of Equity Securities:

Period	Total Number of Shares Purchased	Average Price Paid Per Share1		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 Programs2,3 (in thousands)
July 1 through July 31, 2023	—	$	—	—	$	300,000
August 1 through August 31, 2023	1,125,564	$	44.42	1,125,564	$	250,000
September 1 through September 30, 2023	558,958	$	44.71	558,958	$	225,000

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

2 In August 2022, the Company’s Board of Directors authorized a share repurchase program of up to $300 million of the Company’s Common Stock. 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. Maximum approximate values reported represent amounts at end of the month. During the nine months ended September 30, 2023, the Company repurchased 1,684,522 shares of its Common Stock under the share repurchase program in open-market transactions for $75.0 million, excluding taxes and fees.

3 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.

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 6. EXHIBITS

The Exhibit Index on page 39 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

37

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

MURPHY OIL CORPORATION
(Registrant)
By	/s/ PAUL D. VAUGHAN
	Paul D. Vaughan
	Vice President and Controller
	(Chief Accounting Officer and Duly Authorized Officer)

November 2, 2023

(Date)

38

EXHIBIT INDEX

The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.

Exhibit No.
*31.1	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS	Inline XBRL Instance Document
101. SCH	Inline XBRL Taxonomy Extension Schema Document
101. CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	Inline XBRL Taxonomy Extension Labels Linkbase Document
101. PRE	Inline XBRL Taxonomy Extension Presentation Linkbase
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

39