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~~March 31, 2024


☐			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~~April 30, 2024 was ~~154,473,141.~~152,576,275.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


			Page
Part I – Financial Information
Item 1. Financial Statements			2
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			1615
Note M – Accumulated Other Comprehensive Loss			1817
Note N – Environmental and Other Contingencies			1918
Note O – Common Stock Issued and Outstanding			2019
Note P – Business Segments			2120



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			3738
Item 6. Exhibits			3738
Signature			3839

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


(Thousands of dollars, except share amounts)	(Thousands of dollars, except share amounts)	September 30, 2023		December 31, 2022		(Thousands of dollars, except share amounts)	March 31, 2024	December 31, 2023
ASSETS	ASSETS
Current assets	Current assets
Current assets
Current assets
Cash and cash equivalents
Cash and cash equivalents
Cash and cash equivalents	Cash and cash equivalents	$	327,769	$	491,963
Accounts receivable, net	Accounts receivable, net	460,630		391,152
Inventories	Inventories	60,435		54,513
Prepaid expenses	Prepaid expenses	38,177		34,697

Total current assets	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
Total current assets
Total current assets
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $13,309,133 in 2024 and $13,135,385 in 2023
Operating lease assets	Operating lease assets	792,149		946,406
Deferred income taxes	Deferred income taxes	1,111		117,889
Deferred charges and other assets	Deferred charges and other assets	44,292		44,316

Total assets	Total assets	$	9,942,578	$	10,308,952
Total assets
Total assets
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY
Current liabilities	Current liabilities
Current liabilities
Current liabilities
Current maturities of long-term debt, finance lease
Current maturities of long-term debt, finance lease
Current maturities of long-term debt, finance lease	Current maturities of long-term debt, finance lease	$	714	$	687
Accounts payable	Accounts payable	449,960		543,786
Income taxes payable	Income taxes payable	24,000		26,544
Other taxes payable	Other taxes payable	34,335		22,819
Operating lease liabilities	Operating lease liabilities	245,884		220,413
Other accrued liabilities	Other accrued liabilities	137,500		443,585

Total current liabilities	Total current liabilities	892,393		1,257,834
Total current liabilities
Total current liabilities
Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation	1,576,279		1,822,452
Asset retirement obligations	Asset retirement obligations	859,123		817,268
Deferred credits and other liabilities	Deferred credits and other liabilities	289,962		304,948
Non-current operating lease liabilities	Non-current operating lease liabilities	561,254		742,654
Deferred income taxes	Deferred income taxes	250,768		214,903

Total liabilities	Total liabilities	$	4,429,779	$	5,160,059
Total liabilities
Total liabilities
Equity	Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	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
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
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 2024 and 195,100,628 shares in 2023
Capital in excess of par value	Capital in excess of par value	869,132		893,578
Retained earnings	Retained earnings	6,472,114		6,055,498
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(533,940)		(534,686)
Treasury stock	Treasury stock	(1,662,376)		(1,614,717)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	5,340,031		4,994,774
Noncontrolling interest	Noncontrolling interest	172,768		154,119
Total equity	Total equity	5,512,799		5,148,893
Total liabilities and equity	Total liabilities and equity	$	9,942,578	$	10,308,952

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


		Three Months Ended September 30,				Nine Months Ended September 30,
				Three Months Ended March 31,
				Three Months Ended March 31,
				Three Months Ended March 31,
(Thousands of dollars, except per share amounts)	(Thousands of dollars, except per share amounts)	2023		2022		2023		2022		(Thousands of dollars, except per share amounts)	2024	2023
Revenues and other income	Revenues and other income
Revenue from production	Revenue from production	$	945,889	$	1,120,909	$	2,541,956	$	3,101,736
Revenue from production
Revenue from production
Sales of purchased natural gas	Sales of purchased natural gas	7,877		45,500		64,628		132,285
Total revenue from sales to customers	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
Gain on sale of assets and other income
Gain on sale of assets and other income	Gain on sale of assets and other income	5,879		21,825		9,365		32,076
Total revenues and other income	Total revenues and other income	959,645		1,303,425		2,615,949		2,957,443
Costs and expenses	Costs and expenses
Lease operating expenses
Lease operating expenses
Lease operating expenses	Lease operating expenses	193,402		198,710		587,678		482,887
Severance and ad valorem taxes	Severance and ad valorem taxes	10,937		15,140		35,142		47,340
Transportation, gathering and processing	Transportation, gathering and processing	61,518		55,348		175,308		152,219
Costs of purchased natural gas	Costs of purchased natural gas	5,467		43,622		47,393		125,258
Exploration expenses, including undeveloped lease amortization	Exploration expenses, including undeveloped lease amortization	26,514		9,491		152,489		72,208
Selling and general expenses	Selling and general expenses	30,745		29,348		74,398		90,007

Depreciation, depletion and amortization	Depreciation, depletion and amortization	237,493		214,521		648,830		574,501
Depreciation, depletion and amortization
Depreciation, depletion and amortization
Accretion of asset retirement obligations	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
Other operating expense
Impairment of assets
Total costs and expenses	Total costs and expenses	582,136		550,337		1,776,767		1,694,871
Operating income from continuing operations	Operating income from continuing operations	377,509		753,088		839,182		1,262,572
Other loss	Other loss
Other income		8,811		18,301		1,044		21,114
Other income (loss)
Other income (loss)
Other income (loss)
Interest expense, net	Interest expense, net	(29,984)		(37,440)		(88,695)		(116,102)
Total other loss	Total other loss	(21,173)		(19,139)		(87,651)		(94,988)
Income from continuing operations before income taxes	Income from continuing operations before income taxes	356,336		733,949		751,531		1,167,584
Income tax expense	Income tax expense	78,111		159,451		166,813		247,574
Income from continuing operations	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)
(Loss) gain from discontinued operations, net of income taxes
Net income including noncontrolling interest	Net income including noncontrolling interest	277,804		574,076		583,974		918,094
Less: Net income attributable to noncontrolling interest	Less: Net income attributable to noncontrolling interest	22,462		45,648		38,701		152,445
NET INCOME ATTRIBUTABLE TO MURPHY	NET INCOME ATTRIBUTABLE TO MURPHY	$	255,342	$	528,428	$	545,273	$	765,649
INCOME PER COMMON SHARE – BASIC
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations
Continuing operations
Continuing operations	Continuing operations	$	1.64	$	3.40	$	3.50	$	4.94
Discontinued operations	Discontinued operations	–		–		–		(0.01)
Net income	Net income	$	1.64	$	3.40	$	3.50	$	4.93
INCOME (LOSS) PER COMMON SHARE – DILUTED	INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations
Continuing operations
Continuing operations	Continuing operations	$	1.63	$	3.36	$	3.47	$	4.87
Discontinued operations	Discontinued operations	–		–		–		(0.01)
Net income	Net income	$	1.63	$	3.36	$	3.47	$	4.86
Cash dividends per common share	Cash dividends per common share	$	0.275	$	0.250	$	0.827	$	0.575

Average common shares outstanding (thousands)	Average common shares outstanding (thousands)
Average common shares outstanding (thousands)
Average common shares outstanding (thousands)
Basic
Basic
Basic	Basic	155,454		155,446		155,749		155,221
Diluted	Diluted	156,829		157,336		157,135		157,407

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)


		Three Months Ended September 30,				Nine Months Ended September 30,
				Three Months Ended March 31,
				Three Months Ended March 31,
				Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2023		2022		2023		2022		(Thousands of dollars)	2024	2023
Net income including noncontrolling interest	Net income including noncontrolling interest	$	277,804	$	574,076	$	583,974	$	918,094
Other comprehensive (loss) income, net of tax	Other comprehensive (loss) income, net of tax
Net gain (loss) from foreign currency translation		(39,353)		(102,266)		(2,601)		(135,791)
Net (loss) gain from foreign currency translation
Net (loss) gain from foreign currency translation
Net (loss) gain from foreign currency translation
Retirement and postretirement benefit plans	Retirement and postretirement benefit plans	1,196		3,165		3,347		9,674

Other comprehensive (loss) income	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

Other comprehensive (loss) income

Other comprehensive (loss) income
Comprehensive income including noncontrolling interest
Less: Comprehensive income attributable to noncontrolling interest	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
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


		Nine Months Ended September 30,
	Three Months Ended March 31,								Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2023		2022		(Thousands of dollars)	2024	2023
Operating Activities	Operating Activities
Net income including noncontrolling interest	Net income including noncontrolling interest	$	583,974	$	918,094
Net income including noncontrolling interest
Net income including noncontrolling interest
Adjustments to reconcile net income to net cash provided by continuing operations activities	Adjustments to reconcile net income to net cash provided by continuing operations activities
Loss from discontinued operations		744		1,916
Depreciation, depletion and amortization	Depreciation, depletion and amortization	648,830		574,501
Depreciation, depletion and amortization
Depreciation, depletion and amortization
Impairment of assets
Unsuccessful exploration well costs and previously suspended exploration costs	Unsuccessful exploration well costs and previously suspended exploration costs	107,825		35,224
Deferred income tax expense
Accretion of asset retirement obligations
Long-term non-cash compensation
Amortization of undeveloped leases	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

Loss (income) from discontinued operations

Loss (income) from discontinued operations

Loss (income) from discontinued operations

Contingent consideration payment
Contingent consideration payment
Contingent consideration payment	Contingent consideration payment	(139,574)		–
Mark to market loss on contingent consideration	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
Other operating activities, net
Net increase in noncash working capital

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
Net cash provided by continuing operations activities
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	1,205,734		1,678,726
Investing Activities	Investing Activities
Property additions and dry hole costs	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)
Property additions and dry hole costs
Property additions and dry hole costs

Net cash required by investing activities

Net cash required by investing activities

Net cash required by investing activities	Net cash required by investing activities	(822,155)		(928,599)
Financing Activities	Financing Activities
Borrowings on revolving credit facility	Borrowings on revolving credit facility	300,000		300,000
Borrowings on revolving credit facility
Borrowings on revolving credit facility
Repayment of revolving credit facility	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	Repurchase of common stock	(75,023)		—

Repurchase of common stock

Repurchase of common stock
Cash dividends paid
Withholding tax on stock-based incentive awards
Distributions to noncontrolling interest
Finance lease obligation payments
Contingent consideration payment	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	Issue costs of debt facility	(20)		–

Net cash required by financing activities
Net cash required by financing activities
Net cash required by financing activities	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	Effect of exchange rate changes on cash and cash equivalents	(414)		(5,180)
Net decrease in cash and cash equivalents		(164,194)		(55,186)

Effect of exchange rate changes on cash and cash equivalents

Effect of exchange rate changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period	491,963		521,184
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	327,769	$	465,998

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


				Three Months Ended March 31,
				Three Months Ended March 31,
				Three Months Ended March 31,
(Thousands of dollars except number of shares)										(Thousands of dollars except number of shares)	2024	2023
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 March 31, 2024 and 195,100,628 shares at March 31, 2023

		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

Balance at beginning and end of period

Balance at beginning and end of period	Balance at beginning and end of period	195,101		195,101		195,101		195,101
Capital in Excess of Par Value	Capital in Excess of Par Value
Balance at beginning of period	Balance at beginning of period	861,951		883,368		893,578		926,698
Balance at beginning of period
Balance at beginning of period

Restricted stock transactions and other
Restricted stock transactions and other
Restricted stock transactions and other	Restricted stock transactions and other	44		(1,956)		(42,371)		(57,760)
Share-based compensation	Share-based compensation	7,137		6,318		17,925		18,792

Balance at end of period	Balance at end of period	869,132		887,730		869,132		887,730
Balance at end of period
Balance at end of period
Retained Earnings	Retained Earnings
Balance at beginning of period
Balance at beginning of period
Balance at beginning of period	Balance at beginning of period	6,259,561		5,405,400		6,055,498		5,218,670
Net income attributable to Murphy	Net income attributable to Murphy	255,342		528,428		545,273		765,649

Cash dividends paid	Cash dividends paid	(42,789)		(38,863)		(128,657)		(89,354)

Cash dividends paid

Cash dividends paid
Balance at end of period	Balance at end of period	6,472,114		5,894,965		6,472,114		5,894,965
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss
Balance at beginning of period
Balance at beginning of period
Balance at beginning of period	Balance at beginning of period	(495,783)		(554,727)		(534,686)		(527,711)
Foreign currency translation (loss) gain, net of income taxes	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	Retirement and postretirement benefit plans, net of income taxes	1,196		3,165		3,347		9,674

Balance at end of period	Balance at end of period	(533,940)		(653,828)		(533,940)		(653,828)

Balance at end of period

Balance at end of period
Treasury Stock	Treasury Stock
Balance at beginning of period	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)		–
Balance at beginning of period
Balance at beginning of period
Repurchase of common stock
Awarded restricted stock, net of forfeitures	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)
Balance at end of period – 42,524,472 shares of common stock in 2024 and 39,002,553 shares of common stock in 2023, at cost
Balance at end of period – 42,524,472 shares of common stock in 2024 and 39,002,553 shares of common stock in 2023, at cost
Balance at end of period – 42,524,472 shares of common stock in 2024 and 39,002,553 shares of common stock in 2023, at cost
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	5,340,031		4,708,941		5,340,031		4,708,941
Noncontrolling Interest	Noncontrolling Interest
Balance at beginning of period	Balance at beginning of period	154,375		175,428		154,119		163,485
Balance at beginning of period
Balance at beginning of period

Net income attributable to noncontrolling interest
Net income attributable to noncontrolling interest
Net income attributable to noncontrolling interest	Net income attributable to noncontrolling interest	22,462		45,648		38,701		152,445
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(4,069)		(50,419)		(20,052)		(145,273)
Balance at end of period	Balance at end of period	172,768		170,657		172,768		170,657
Total Equity	Total Equity	$	5,512,799	$	4,879,598	$	5,512,799	$	4,879,598

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

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~~March 31, 2024 and December 31, ~~2022,~~2023, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended ~~September 30,~~March 31, 2024 and 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~~2023 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~~period ended ~~September 30, 2023~~March 31, 2024 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.~~None affecting the Company.

Recent Accounting Pronouncements

~~None affecting~~Income Tax Disclosures. In December 2023 the ~~Company.~~Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. Murphy is currently evaluating the impact of adopting this standard.

Reportable Segment Disclosures. In November 2023 the FASB issued ASU 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The standard becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. The standard does not affect our determination of significant segments. Murphy is currently evaluating the impact of adopting this standard.

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.~~United States (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.~~GAAP.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

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

~~Table of Contents~~

~~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~~physical forward ~~physical~~sales fixed-price 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
The Company’s revenues and other income for the three-month periods ended March 31, 2024 and 2023 were as follows.


		Three Months Ended March 31,
(Thousands of dollars)			2024		2023
Net crude oil and condensate revenue
United States	Onshore		$	142,543	$	130,081
	Offshore 1		480,439		500,310
Canada	Onshore		13,873		21,952
	Offshore		54,775		16,130
Other			(98)		3,644
Total crude oil and condensate revenue			691,532		672,117

Net natural gas liquids revenue
United States	Onshore		7,836		8,270
	Offshore 1		10,374		14,629
Canada	Onshore		1,437		3,463
Total natural gas liquids revenue			19,647		26,362

Net natural gas revenue
United States	Onshore		4,276		5,450
	Offshore 1		12,889		22,132
Canada	Onshore		66,259		70,170
Total natural gas revenue			83,424		97,752

Revenue from production			794,603		796,231

Sales of purchased natural gas



Canada	Onshore		245		43,737
Total sales of purchased natural gas			245		43,737

Total revenue from sales to customers			794,848		839,968


Gain on sale of assets and other income			1,564		1,748
Total revenues and other income			$	796,412	$	841,716

1 Includes revenue attributable to noncontrolling interest in MP GOM.

Contract Balances and Asset Recognition

As of ~~September 30, 2023,~~March 31, 2024, and December 31, ~~2022,~~2023, receivables from contracts with customers, net of royalties and associated payables, on the balance ~~sheets,~~sheet from continuing operations, were ~~$248.8~~$215.2 million and ~~$201.1~~$193.7 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

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.~~

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)~~

~~Note C - Revenue from Contracts with Customers (Continued)~~

March 31, 2024.

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 assets to be recognized associated with the costs ~~incurred~~ to obtain a contract with a ~~customer that should be recognized as an asset.~~customer.

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,~~March 31, 2024, 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~~over 12 months starting at the inception of the contract:

~~Current~~ Long-Term Contracts Outstanding at ~~September 30, 2023~~March 31, 2024

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~~2024

Contracts to sell natural gas at USD index pricing

2531 MMCFD

Canada

Natural Gas

Q4 ~~2023~~2024

Contracts to sell natural gas at CAD fixed ~~prices~~pricing

38124 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD fixed pricing

25 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD index pricing

28 MMCFD

Canada

Natural Gas

Q4 2025

Contracts to sell natural gas at USD index pricing

3125 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~~pricing

2030 MMCFD

Canada

~~NGL~~Natural Gas

~~Q1 2024~~Q4 2028

Contracts to sell natural gas ~~liquids~~ at ~~various CAD~~USD index pricing

~~As produced~~10 MMCFD

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment

Exploratory Wells

Under ~~Financial Accounting Standards Board~~FASB 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~~company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

As of ~~September 30, 2023,~~March 31, 2024, the Company had total capitalized ~~exploratory well~~drilling costs pending the determination of proved reserves of ~~$185.5~~$34.2 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~nine-month~~three-month periods ended ~~September 30, 2023~~March 31, 2024 and ~~2022.~~2023.


(Thousands of dollars)	(Thousands of dollars)	2023		2022		(Thousands of dollars)	2024	2023
Beginning balance at January 1	Beginning balance at January 1	$	171,860	$	179,481
Additions pending the determination of proved reserves	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	Capitalized exploratory well costs charged to expense	(26,143)		(20,295)
Balance at September 30		$	185,477	$	181,461
Capitalized exploratory well costs charged to expense
Capitalized exploratory well costs charged to expense
Balance at March 31

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~~$26.5 million for the ~~nine~~three months ended ~~September 30, 2023 are~~March 31, 2024 was related to ~~Cholula-1EXP~~the Hoffe Park #1 (Mississippi Canyon 166) exploratory well in ~~Mexico~~the Gulf of Mexico. Capital additions include the Orange #1 (Mississippi Canyon 216) and ~~Chinook #7 (Walker Ridge 425) exploration well~~Ocotillo #1 (Mississippi Canyon 40) exploratory wells in the Gulf of Mexico. The preceding table excludes well costs of ~~$81.7~~$5.9 million incurred and expensed directly to dry hole during the ~~nine~~three months ended ~~September 30, 2023,~~March 31, 2024, mainly related to the ~~Chinook #7 (Walker Ridge 425)~~Oso #1 (Atwater Valley 138) 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
	March 31,														March 31,
	2024											2024					2023

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

Of the ~~$185.5~~$22.5 million of exploratory well costs capitalized more than one year at ~~September 30, 2023, $112.8~~March 31, 2024, $15.1 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 imp~~pre-tax impairments of $34.5 million i~~airments~~n the three months ended March 31, 2024 related to Calliope field in the ~~nine~~Mississippi Canyon block in the Gulf of Mexico in which operational issues led to a reserve reduction. There were no impairments in the three months ended ~~September 30, 2023 or 2022.~~March 31, 2023.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt

As of ~~September 30, 2023,~~March 31, 2024, 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,~~March 31, 2024, the Company had no outstanding borrowings under the RCF and ~~$4.1~~$3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At ~~September 30, 2023,~~March 31, 2024, the interest rate in effect on borrowings under the RCF would have been ~~7.92%~~7.68%. At ~~September 30, 2023,~~March 31, 2024, 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,
	Three Months Ended March 31,								Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2023		2022		(Thousands of dollars)	2024	2023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:	Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) in accounts receivable		$	(69,689)	$	(130,792)
(Increase) decrease in accounts receivable
(Increase) decrease in accounts receivable
(Increase) decrease in accounts receivable
(Increase) decrease in inventories	(Increase) decrease in inventories	(6,609)		(410)
(Increase) in prepaid expenses		(3,364)		(8,561)
Decrease in prepaid expenses
Increase (decrease) in accounts payable and accrued liabilities ¹	Increase (decrease) in accounts payable and accrued liabilities ¹	(60,582)		61,139
Increase (decrease) in income taxes payable	Increase (decrease) in income taxes payable	(2,544)		18,750
Net increase in noncash working capital	Net increase in noncash working capital	$	(142,788)	$	(59,874)
Supplementary disclosures:	Supplementary disclosures:
Cash income taxes paid, net of refunds	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
Cash income taxes paid, net of refunds
Cash income taxes paid, net of refunds
Interest paid, net of amounts capitalized of $3.9 million in 2024 and $3.3 million in 2023

Non-cash investing activities:	Non-cash investing activities:
Non-cash investing activities:
Non-cash investing activities:
Asset retirement costs capitalized	Asset retirement costs capitalized	$	16,219	$	29,327
Decrease in capital expenditure accrual		75,760		34,853
Asset retirement costs capitalized
Asset retirement costs capitalized
(Increase) decrease in capital expenditure accrual

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

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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~~three-month periods ended ~~September 30,~~March 31, 2024 and 2023 ~~and 2022~~ is shown in the following table.


(Thousands of dollars)	(Thousands of dollars)	September 30, 2023		September 30, 2022		(Thousands of dollars)	March 31, 2024	March 31, 2023
Balance at beginning of year	Balance at beginning of year	$	911,653	$	971,893
Accretion	Accretion	34,196		34,725
Liabilities incurred	Liabilities incurred	16,441		(18,555)

Revisions of previous estimates	Revisions of previous estimates	(822)		–
Revisions of previous estimates
Revisions of previous estimates
Liabilities settled	Liabilities settled	(89,340)		(28,927)

Changes due to translation of foreign currencies

Changes due to translation of foreign currencies

Changes due to translation of foreign currencies	Changes due to translation of foreign currencies	(340)		(13,592)
Balance at end of period	Balance at end of period	871,788		945,544
Current portion of liability 1	Current portion of liability 1	(12,665)		(96,937)
Noncurrent portion of liability	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.

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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~~March 31, 2024 and ~~2022.~~2023.


		Three Months Ended September 30,
		Pension Benefits				Other Postretirement Benefits
	Three Months Ended March 31,														Three Months Ended March 31,
	Pension Benefits												Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2023		2022		2023		2022		(Thousands of dollars)	2024	2023		2024			2023
Service cost	Service cost	$	1,650	$	2,129	$	132	$	292
Interest cost	Interest cost	8,534		5,163		874		574
Expected return on plan assets	Expected return on plan assets	(8,223)		(7,999)		–		–
Estimated defined contribution provision	Estimated defined contribution provision	53		–		–		–
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	155		582		(133)		(133)
Recognized actuarial loss (gain)	Recognized actuarial loss (gain)	2,407		3,822		(767)		(77)

Total net periodic benefit expense	Total net periodic benefit expense	$	4,576	$	3,697	$	106	$	656

		Nine Months Ended September 30,
Total net periodic benefit expense
		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	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”~~income (loss)” in the Consolidated Statements of Operations.

During the ~~nine-month~~three-month period ended ~~September 30, 2023,~~March 31, 2024, the Company made contributions of ~~$31.5~~$9.5 million to its defined benefit pension and postretirement benefit plans. Remaining funding in ~~2023~~2024 for the Company’s defined benefit pension and postretirement plans is anticipated to be ~~$5.5~~$31.7 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.

~~Table of Contents~~

~~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~~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~~term of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the 2020 Long-Term 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~~Shares underlying awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I - Incentive Plans (Continued)

During the ~~nine~~three months ended ~~September 30, 2023,~~March 31, 2024, 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


Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Performance-based RSUs (TSR) 1	423,640	February 6, 2024	$	41.95	Monte Carlo
Performance-based RSUs (ROACE) 1	105,980	February 6, 2024	$	38.08	Average Stock Price
Time-based RSUs (Stock-Settled) 2	658,420	February 6, 2024	$	38.08	Average Stock Price
Time-based RSUs (Cash-Settled) 2	102,900	February 6, 2024	$	38.08	Average Stock Price

1 ~~Performance based~~Performance-based RSUs are tied to the achievement of TSR and ROACE performance goals and scheduled to vest over a ~~three year~~three-year performance period.

2 ~~Time based~~Time-based RSUs ~~are~~ generally ~~scheduled to~~ vest ~~over three years from~~on the ~~date~~third anniversary 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~~three months ended ~~September 30, 2023,~~March 31, 2024, the Committee granted the following awards to Non-Employee ~~Directors:~~Directors under the 2021 NED Plan:

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

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

Time-Based RSUs 1

47,412

February 07, 2024

37.97

Closing Stock Price

Time-Based RSUs 2

1,230

March 28, 2024

45.70

Closing Stock Price

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

~~All stock option exercises are non-cash transactions for~~on the ~~Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized~~first anniversary of the date of grant. Non-employee directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the ~~tax deductions related~~Board or (2) a future date selected by the director at the time of their deferral election. These unvested time-based RSUs are included in the table above, will vest in one year and become deferred RSUs.

2 Effective January 1, 2024, non-employee directors can elect to ~~stock option exercises~~receive their annual cash retainers in the form of deferred RSUs. Director fees which are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the ~~share-based payment arrangements~~applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.

In 2017, the Company ceased granting stock options and SARs as a part of the Company’s long-term incentive compensation program. As of December 31, 2023 there were ~~immaterial for the nine-month period ended September 30, 2023.~~no outstanding stock options or SARs remaining.

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


		Nine Months Ended September 30,
	Three Months Ended March 31,								Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2023		2022		(Thousands of dollars)	2024	2023
Compensation charged against income before tax benefit	Compensation charged against income before tax benefit	$	42,912	$	43,216
Related income tax benefit recognized in income	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).

Table of Contents

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~~common share for the three-month ~~and nine-month~~ periods ended ~~September 30, 2023~~March 31, 2024 and ~~2022.~~2023. 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


	Three Months Ended March 31,
(Weighted-average shares)		2024	2023
Basic method		152,664,422	155,856,509
Dilutive stock options and restricted stock units		1,152,204	1,532,057
Diluted method		153,816,626	157,388,566

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,~~March 31, 2024 and 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%


	2024	2023

Three months ended March 31,	20.6%	20.1%

The effective tax rate for the three-month ~~period~~periods ended ~~September 30,~~March 31, 2024 and March 31, 2023, was ~~above~~below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, and partially offset by 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

~~Table of Contents~~

~~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~~could be required to pay amounts into an escrow account as any matters are identified and ~~may from time to time pay more amounts into escrow, in order to continue tax disputes~~appealed with the relevant taxing authorities. As of ~~September 30, 2023,~~March 31, 2024, 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~~2017. 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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Commodity Price Risks

During the ~~third~~first quarter of 2024 and 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~~March 31, 2024 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)

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)~~

~~Note L – Financial Instruments and Risk Management (Continued)~~

2023.

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~~fair value ofmeasurements for these assets and liabilities ~~recorded~~ at ~~fair value on a recurring basis at September 30, 2023~~March 31, 2024 and December 31, ~~2022,~~2023, are ~~presented~~shown in the following table.

September 30, 2023

December 31, 2022

March 31, 2024

December 31, 2023

(Thousands of dollars)

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

(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

Nonqualified employee savings plan

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~~March 31, 2024 and ~~collars contracts subject to fair value measurement.~~

~~As of~~ December 31, ~~2022,~~2023, 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~~measurement, nor were ~~based on realized WTI pricing. The~~there any 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.~~liabilities.

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~~were 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~~three months ended ~~September 30,~~March 31, 2023, the Company paid a total of ~~$199.8~~$171.7 million in contingent consideration payments. In the Consolidated Statements of Cash Flows, ~~$139.6~~$124.0 million is shown in “Operating Activities” and ~~$60.2~~$47.7 million is shown in “Financing Activities”.

~~Table of Contents~~

~~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~~March 31, 2024 and December 31, ~~2022.~~2023.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at ~~September 30, 2023~~March 31, 2024 and December 31, ~~2022.~~2023. 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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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

March 31,

December 31,

2024

2023

(Thousands of dollars)

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

(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

Current and long-term debt

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, ~~2022~~2023 and ~~September 30, 2023~~March 31, 2024 and the changes during the ~~nine-month~~three-month period ended ~~September 30, 2023~~March 31, 2024 are presented net of taxes in the following table.


(Thousands of dollars)	(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)
(Thousands of dollars)
(Thousands of dollars)								Foreign Currency Translation Gains (Losses)	Retirement and Postretirement Benefit Plan Adjustments	Total
Balance at December 31, 2023
Components of other comprehensive income (loss):	Components of other comprehensive income (loss):
Before reclassifications to income
Before reclassifications to income
Before reclassifications to income	Before reclassifications to income	(2,601)		–		(2,601)
Reclassifications to income ¹	Reclassifications to income ¹	–		3,347		3,347
Net other comprehensive income (loss)	Net other comprehensive income (loss)	(2,601)		3,347		746
Balance at September 30, 2023		$	(420,831)	$	(113,109)	$	(533,940)
Balance at March 31, 2024

1 Reclassifications before taxes of ~~$4,146 thousand~~$1.2 million are included in the computation of net periodic benefit expense for the ~~nine-month~~three-month period ended ~~September 30, 2023.~~March 31, 2024. See Note H for additional information. Related income taxes of ~~$799 thousand~~$0.3 million are included in "Income tax expense” on the Consolidated Statements of Operations for the ~~nine-month~~three-month period ended ~~September 30, 2023.~~March 31, 2024.

1817

Table of Contents

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~~U.S. 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 of 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~~environmental 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~~federal methane regulations currently pending or enacted that ~~impose~~would, among other things, require increased leak detection monitoring and repairs, stringent restrictions on venting and flaring, a new third-party monitoring program, and new fees ~~for excess~~on 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~~

1918

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

contaminated property (including contaminated groundwater) or to perform remedial plugging operations to 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~~common stock issued and outstanding for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2024 and 2023 ~~and 2022~~ is shown below.

(Number of shares outstanding)

September 30, 2023

September 30, 2022

(Number of shares outstanding)

Beginning of period

155,467,319

154,463,050

Stock options exercised 1

520

169,619

Beginning of period

Restricted stock awards 1

689,824

822,614

Treasury shares purchased 2

1,684,522

–

Restricted stock awards 1

Treasury shares purchased

End of period

154,473,141

155,455,283

End of period

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.~~common stock. On October 30, 2023, the Company authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million. 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. The share repurchase program is a component of the Company’s capital allocation framework, the details of which can be found as part of the Company’s Form 8-K filed on August 4, 2022.

During the three ~~and nine~~ months ended ~~September 30, 2023,~~March 31, 2024, the Company repurchased ~~1,684,522~~1.3 million shares of its ~~Common Stock~~common stock under the share repurchase program for ~~$75.8~~$50.0 million, including excise taxes, commissions and fees.

~~Subsequent to~~ As of March 31, 2024, the ~~third quarter~~Company has $400 million 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 millionits common stock remaining available to ~~repurchase.~~repurchase under the program.

2019

Table of Contents

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.), Malaysia, 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
					Total Assets at March 31, 2024											Total Assets at March 31, 2024		Three Months Ended March 31, 2024			Three Months Ended March 31, 2023
(Millions of dollars)		(Millions of dollars)				Total Assets at September 30, 2023		External Revenues		Income (Loss)		External Revenues		Income (Loss)	(Millions of dollars)		External Revenues		Income (Loss)	External Revenues		Income (Loss)
Exploration and production ¹	Exploration and production ¹
United States
United States
United States	United States		$	6,925.0		$	823.7	$	310.3	$	973.8	$	481.5
Canada	Canada		2,074.7			129.3		10.5		209.6		41.4
Other	Other		226.9			3.4		(12.5)		4.8		(5.8)
Total exploration and production	Total exploration and production		9,226.6			956.4		308.3		1,188.2		517.1
Corporate	Corporate		714.9			3.2		(30.1)		115.2		57.4
Continuing operations	Continuing operations		9,941.5			959.6		278.2		1,303.4		574.5
Discontinued operations, net of tax	Discontinued operations, net of tax		1.1			–		(0.4)		–		(0.4)
Total	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

1Additional detail about the results of oil and natural gas operations is presented in the Exploration and Production Continuing Operations table on page 2423.

2120

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended ~~September 30, 2023~~March 31, 2024 included under Item 1.1 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.~~2023. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See Forward-Looking Statements at the end of this section.

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~~first quarter of ~~2023~~2024 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~~176,671 barrels of oil equivalent per day (including NCI).

•Exploration areas expanded with the award of six deepwater blocks from Gulf of Mexico Federal Lease Sale 261

•Repurchased shares of our common stock under the share repurchase program for $50.0 million, including excise taxes, commissions and fees.

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended ~~September 30, 2023~~March 31, 2024 was ~~$278.2~~$115.6 million, a decrease of ~~$296.3~~$98.5 million compared to the same period ~~in 2022.~~of 2023. Lower net income from continuing operations was largely driven by ~~lower revenues and other income~~higher lease operating expenses ($~~343.8~~34.3 million), higher exploration expenses ($34.2 million), and higher ~~other operating expenses~~impairment of assets ($~~31.5~~34.5 million), partially offset by lower income tax expense ($~~81.3~~23.8 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~~lease operating expenses ~~were due~~related to ~~lower contingent consideration adjustments (relating to prior acquisitions~~workovers in the Gulf of ~~Mexico).~~Mexico and ramp up of production from the Terra Nova field in Canada Offshore following the completion of the asset life extension project in the fourth quarter of 2023. Higher exploration costs were the result of dry hole expense for the previously suspended exploration costs for Hoffe Park #1 (Mississippi Canyon166) and additional costs related to Oso #1 (Atwater Valley 138) exploration well in the Gulf of Mexico. The Mississippi Canyon Block 166 lease will expire in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and operations finished in the first quarter of 2024. Lower income tax expense was the result of lower pre-tax income.

For the three months ended ~~September 30, 2023,~~March 31, 2024, total hydrocarbon production was ~~208,200~~176,671 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~~2% compared to the same period ~~of 2022. Lower net income from continuing operations~~in 2023. The decrease was ~~largely driven by~~principally due to 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 wellproduction 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 increased downtime for workovers, which was substantially offset by an increase in volumes at Tupper Montney from new well production and lower ~~contingent consideration adjustments relating~~royalty rates and an increase in production from the Terra Nova field in Canada Offshore due to ~~prior acquisitions in~~ the ~~Gulf~~restart of ~~Mexico. Lower income tax expense was the result of lower pre-tax income.~~production.

2221

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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 Net income (loss) by type of business and geographic segment is presented below.


		Income (Loss)
		Three Months Ended September 30,					Nine Months Ended September 30,
							Income (Loss)
							Income (Loss)
							Income (Loss)
				Three Months Ended March 31,									Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2023			2022		2023		2022		(Millions of dollars)	2024		2023
Exploration and production	Exploration and production
United States
United States
United States	United States	$	310.3		$	481.5	$	705.2	$	1,225.9
Canada	Canada	10.5			41.4		34.9		111.3
Other	Other	(12.5)			(5.8)		(50.0)		(53.5)
Total exploration and production	Total exploration and production	308.3			517.1		690.1		1,283.7
Corporate and other	Corporate and other	(30.1)			57.4		(105.4)		(363.7)
Income from continuing operations	Income from continuing operations	278.2			574.5		584.7		920.0
Discontinued operations ¹	Discontinued operations ¹	(0.4)			(0.4)		(0.7)		(1.9)
Net income including noncontrolling interest	Net income including noncontrolling interest	277.8			574.1		584.0		918.1
Net income attributable to noncontrolling interest	Net income attributable to noncontrolling interest	22.5			45.7		38.7		152.5
Net income attributable to Murphy	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.

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

Results of Operations (Continued)

Exploration and Production Continuing Operations

The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.

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


	Three Months Ended March 31,
(Millions of dollars)		2024		2023
Revenues and other income
Revenue from production		$	794.6	$	796.2
Sales of purchased natural gas		0.2		43.7
Other income		1.6		1.8
Total revenues and other income		796.4		841.7
Cost and Expenses
Lease operating expenses		234.3		200.0
Severance and ad valorem taxes		10.1		11.4
Transportation, gathering and processing		56.5		53.9
Costs of purchased natural gas		0.2		32.3
Depreciation, depletion and amortization		208.3		192.8
Impairments of assets		34.5		–
Accretion of asset retirement obligations		12.7		11.1
Total exploration expenses		44.4		10.3
Selling and general expenses		6.1		8.9
Other		8.8		13.6
Results of operations before taxes		180.5		307.4
Income tax provisions		37.4		64.7
Results of operations (excluding Corporate segment) 1		$	143.1	$	242.7

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

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

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~~March 31, 2024 and ~~2022.~~2023.


		Three Months Ended September 30,				Nine Months Ended September 30,
				Three Months Ended March 31,
				Three Months Ended March 31,
				Three Months Ended March 31,
(Weighted average sales prices)	(Weighted average sales prices)	2023		2022		2023		2022		(Weighted average sales prices)	2024	2023
Crude oil and condensate – dollars per barrel	Crude oil and condensate – dollars per barrel
United States - Onshore	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
United States - Onshore
United States - Onshore
United States - Offshore 1
Canada - Onshore 2	Canada - Onshore 2	76.33		82.25		73.01		92.31
Canada - Offshore 2	Canada - Offshore 2	94.85		111.76		84.13		112.93
Other 2	Other 2	77.19		117.18		82.87		92.91
Natural gas liquids – dollars per barrel	Natural gas liquids – dollars per barrel
United States - Onshore	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
United States - Onshore
United States - Onshore
United States - Offshore 1
Canada - Onshore 2	Canada - Onshore 2	37.72		54.40		39.08		57.53
Natural gas – dollars per thousand cubic feet	Natural gas – dollars per thousand cubic feet
United States - Onshore	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
United States - Onshore
United States - Onshore
United States - Offshore 1
Canada - Onshore 2	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.

The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2024 and 2023.


	Three Months Ended March 31,
(Average price for the period)		2024		2023
Oil and NGLs
WTI ($/BBL)		$	76.96	$	76.13
Natural gas
NYMEX ($/MMBTU)		2.42		2.67
AECO (C$/MCF)		2.50		3.22

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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~~March 31, 2024 and ~~2022.~~2023. 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


	Three Months Ended March 31,
(Barrels per day unless otherwise noted)		2024	2023

Net crude oil and condensate
United States - Onshore		20,382	19,277
United States - Offshore 1		66,078	75,699
Canada - Onshore		2,255	3,283
Canada - Offshore		6,264	2,459
Other		245	269
Total net crude oil and condensate		95,224	100,987
Net natural gas liquids
United States - Onshore		4,166	4,157
United States - Offshore 1		4,687	6,342
Canada - Onshore		453	826
Total net natural gas liquids		9,306	11,325
Net natural gas – thousands of cubic feet per day
United States - Onshore		24,231	24,160
United States - Offshore 1		53,161	75,203
Canada - Onshore		355,455	305,232
Total net natural gas		432,847	404,595
Total net hydrocarbons - including NCI 2,3		176,671	179,745
Noncontrolling interest
Net crude oil and condensate – barrels per day		(6,499)	(6,613)
Net natural gas liquids – barrels per day		(211)	(232)
Net natural gas – thousands of cubic feet per day		(2,074)	(2,354)
Total noncontrolling interest 2,3		(7,056)	(7,237)
Total net hydrocarbons - excluding NCI 2,3		169,615	172,508

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

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

3 NCI – noncontrolling interest in MP GOM.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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 and product 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


	Three Months Ended March 31,
(Millions of dollars)		2024		2023
Revenues from production
United States - Oil		$	623.0	$	630.4
United States - Natural gas liquids		18.2		22.9
United States - Natural gas		17.2		27.6
Canada - Oil		68.6		38.1
Canada - Natural gas liquids		1.4		3.4
Canada - Natural gas		66.3		70.2
Other - Oil		(0.1)		3.6
Total revenue from production		$	794.6	$	796.2

Revenue from production for the three months ended ~~September 30, 2023~~March 31, 2024 decreased by ~~$175.0~~$1.6 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.~~2023. 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~~due to increased downtime for workovers, partially offset by higher sales volumes at Eagle Ford Shale assets from new ~~wells from~~well production and higher realized prices at both Eagle Ford Shale assets and the ~~Khaleesi, Mormont, Samurai field development project. Lower~~Gulf of Mexico. Higher revenue from Canadian E&P was primarily attributable to higher sales volumes from Terra Nova and Tupper Montney fields, partially offset by lower ~~realized prices~~pricing at Tupper Montney and lower sales volumes atfrom Kaybob Duvernay ~~partially offset by higher sales~~fields. Tupper Montney had an increase in volumes ~~at Tupper Montney. Lower sales~~as a result of new well production and lower royalty rates, while lower volumes at Kaybob Duvernay ~~were primarily due to natural declines. Higher sales volumes at Tupper~~resulted from the divestiture of certain non-core operated assets and all of our non-operated Placid Montney ~~were~~assets during the ~~result~~second half of ~~new wells coming online~~2023. The Terra Nova field in Canada Offshore restarted production during the fourth quarter of 2023 ~~better well performance and lower royalty rates.~~after completion of the asset life extension project.

~~Sales of purchased natural gas are largely offset with costs to purchase natural gas.~~ Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments.

~~Other Income~~

~~Other Income for the three~~ Sales of purchase natural gas is included in “Total revenues and ~~nine months ended September 30, 2023 decreased by $19.2 million~~other income” and ~~$20.0 million, respectively, compared~~cost to ~~the same periods~~purchase natural gas is included in ~~2022. Lower other income was primarily the result of a gain on sale of the Thunder Hawk field~~“Costs and Expenses” in the ~~third quarter of 2022.~~summarized income statements for E&P continuing operations on page 23.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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 (TGP) expenses by ~~country~~geographic area 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


	Three Months Ended March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
			2024		2023		2024		2023
Lease operating expenses
United States - Onshore			$	35.6	$	37.3	$	13.68	$	15.08
United States - Offshore			151.0		125.3		20.34		14.69
Canada - Onshore			31.0		33.7		5.49		6.81
Canada - Offshore			16.5		3.1		25.91		15.06
Other			0.2		0.6		–		15.05
Total lease operating expenses			$	234.3	$	200.0	$	14.37	$	12.35
TGP expenses
United States - Onshore			2.7		4.1		1.04		1.70
United States - Offshore			33.9		33.3		4.57		3.90
Canada - Onshore			18.0		15.3		3.19		3.10
Canada - Offshore			1.9		1.2		3.03		5.57

Total TGP expenses			$	56.5	$	53.9	$	3.47	$	3.33

Lease operating expenses and TGP 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~~March 31, 2024 increased by ~~$104.8~~$34.3 million and ~~$23.1~~$2.6 million, respectively, compared to the same period in ~~2022.~~2023. Higher lease operating expenses from US E&P was due to workovers in the Gulf of Mexico. Higher lease operating expenses and ~~increased transportation, gathering and processing expenses~~TGP from ~~U.S.~~Canada E&P ~~were primarily due to increased sales volumes and higher operating expenses for additional workover and maintenance activities~~resulted from ramp up of production at the ~~Gulf~~Terra Nova field since the completion of ~~Mexico operations.~~the asset life extension project in the fourth quarter of 2023.

Depreciation, Depletion and Amortization Expense

~~Depreciation,~~The Company’s depreciation, depletion and amortization (DD&A) expense ~~(DD&A)~~by geographic area were as follows:


	Three Months Ended March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
(Millions of dollars)			2024		2023		2024		2023
DD&A expense
United States - Onshore			$	74.1	$	64.6	$	28.52	$	26.18
United States - Offshore			99.9		95.7		13.46		11.22
Canada - Onshore			28.1		29.7		4.99		6.01
Canada - Offshore			6.2		1.9		9.68		9.29
Other			–		0.9		20.38		21.62
Total DD&A expense			$	208.3	$	192.8	$	12.77	$	11.90

DD&A expense for the three ~~and nine~~ months ended ~~September 30, 2023~~March 31, 2024 increased by ~~$23.5~~$15.5 million, ~~and $75.7 million, respectively,~~ compared to the same ~~periods~~period in ~~2022.~~2023. Higher DD&A expense from U.S. E&P resulted from higher sales volumes from the Eagle Ford Shale assets and an overall increase in rates. Higher DD&A expense from Canada E&P was primarily the result of higher sales volumes from Tupper Montney and Terra Nova fields, partially offset by overall lower rates due to fewer sales volumes from Kaybob Duvernay and Placid Montney assets following the ~~Gulf~~sale 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 wella portion of non-core assets in the ~~Gulf of Mexico, which finished during the third~~fourth quarter of 2023.

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

Results of Operations (Continued)

Impairment of Assets

Impairment of assets for the three months ended March 31, 2024 was $34.5 million and related to Calliope field in Mississippi Canyon in the Gulf of Mexico, as a result of operational issues that led to a reserve reduction. There were no impairments in the three months ended March 31, 2023.

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended March 31,
(Millions of dollars)		2024		2023
Exploration expenses
Dry holes and previously suspended exploration costs		$	32.4	$	0.9
Geological and geophysical		1.4		0.8
Other exploration		7.8		5.9
Undeveloped lease amortization		2.8		2.7
Total exploration expenses		$	44.4	$	10.3

Exploration expenses for the ~~nine~~three months ended ~~September 30, 2023~~March 31, 2024 increased by ~~$80.3~~$34.1 million compared to the same period in ~~2022.~~2023. Higher dry holes and previously suspended exploration costs primarily relate to the ~~dry hole expense of Chinook #7 (Walker Ridge 425)~~previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) and additional costs related to the Oso #1 (Atwater Valley 138) exploration well in the Gulf of ~~Mexico, which~~Mexico. The Mississippi Canyon Block 166 lease will expire in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and finished operations in the ~~write-off~~first quarter 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.2024.

Other Expenses

Other expenses for the three months ended ~~September 30, 2023 increased~~March 31, 2024 decreased by ~~$31.2~~$4.8 million compared to the same period in ~~2022.~~2023. Other ~~expense increased~~expenses were lower primarily due to ~~favorable~~an unfavorable contingent consideration adjustment of $3.9 million recorded in ~~2022 ($31.4 million) as a result~~2023 related to prior Gulf of ~~reaching contractual thresholds or time limitations that ended in 2022~~Mexico acquisitions (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~~March 31, 2024 decreased by ~~$54.3~~$27.3 million, ~~and $148.3 million, respectively,~~ compared to the same ~~periods~~period in ~~2022.~~2023. 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.

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

Results of Operations (Continued)

Corporate

Corporate activities include interest expense and income, foreign exchange effects and corporate overhead not allocated to E&P.

Corporate activities reported a loss of $27.5 million for the three months ended March 31, 2024, a favorable variance of $1.2 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($10.9 million) and lower interest expense ($9.0 million), partially offset by increased selling and general expense ($15.7 million) and lower income tax benefits ($3.4 million) .

Interest charges are lower for the three months ended March 31, 2024,primarily due to lower overall debt levels. Higher selling and general expenses were a result of the timing of corporate donations and an increase in provisions for incentive awards. Lower income tax benefit was a result of lower pre-tax losses.

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,
	Three Months Ended March 31,								Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2023		2022		(Thousands of dollars)	2024	2023
Net cash provided by (required by):	Net cash provided by (required by):
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	$	1,205.7	$	1,678.7
Net cash provided by continuing operations activities
Net cash provided by continuing operations activities
Net cash required by investing activities	Net cash required by investing activities	(822.2)		(928.6)
Net cash required by financing activities	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
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	(0.4)		(5.2)
Net increase (decrease) in cash and cash equivalents	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~~three months ended ~~September 30, 2023~~March 31, 2024 was ~~$473.0~~$119.0 million ~~lower~~higher compared to the same period in ~~2022.~~2023. The ~~decrease~~increase was primarily attributable to ~~lower revenue from production ($559.8 million), payments of~~no contingent consideration payments related to prior Gulf of Mexico acquisitions ~~($139.6 million), higher lease operating expenses ($104.8~~in 2024 (2023: $124.0 million) and the timing of working capital settlements ($~~82.9~~50.7 million), partially offset by ~~lower realized losses on derivative instruments~~higher lease operating expenses ($~~447.4~~34.3 million). primarily related to workovers in the Gulf of Mexico. 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~~three months ended ~~September 30,~~March 31, 2023, the Company paid a total of ~~$199.8~~$171.7 million in contingent consideration, of which ~~$139.6~~$124.0 million is shown in “Operating Activities” and ~~$60.2~~$47.7 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~~three months ended ~~September 30, 2023~~March 31, 2024 was ~~$106.4~~$96.2 million lower compared to the same period in ~~2022.~~2023. The decrease was ~~primarily~~ due to ~~the proceeds from the sale of~~ ~~certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets ($102.9 million) and~~ lower ~~acquisition capital ($102.8 million), partially offset by higher~~ p~~roperty~~property additions and dry hole costs ($~~101.4~~96.2 million).

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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,
	Three Months Ended March 31,								Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2023		2022		(Millions of dollars)	2024	2023
Property additions and dry hole costs per cash flow statements	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

Geophysical and other exploration expenses

Geophysical and other exploration expenses	Geophysical and other exploration expenses	30.1		20.4
Capital expenditure accrual changes and other	Capital expenditure accrual changes and other	(69.5)		(28.9)
Total capital expenditures	Total capital expenditures	$	885.7	$	918.0

Total accrual basis capital expenditures are shown below.


		Nine Months Ended September 30,
	Three Months Ended March 31,								Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2023		2022		(Millions of dollars)	2024	2023
Capital Expenditures	Capital Expenditures
Exploration and production	Exploration and production	$	870.3	$	904.1
Exploration and production
Exploration and production
Corporate	Corporate	15.4		13.9
Total capital expenditures	Total capital expenditures	$	885.7	$	918.0

Lower capital expenditures in the ~~E&P business in nine~~three months ended ~~September 30, 2023~~March 31, 2024 compared to the same period of ~~2022~~2023 was primarily attributable to lower development expenditures at ~~the Khaleesi, Mormont, Samurai field development project and lower acquisition capital,~~Eagle Ford Shale assets, partially offset by higher ~~exploratory drilling.~~ development expenditures at various Gulf of Mexico fields.

Capital expenditures in ~~2023~~2024 primarily relate to development drilling and field development activities at Eagle Ford Shale assets ($~~315.2~~53.4 million), development drilling and field development activities at Tupper Montney field ($~~118.7~~47.8 million), development activities in the Gulf of Mexico, primarily related to ~~Dalmatian, Samurai~~Khaleesi, Mormont, Lucius and St. Malo fields ($~~193.3~~106.4 million)~~, field development at Terra Nova for the asset life extension project ($39.5 million),~~ and total exploration costs of ~~$172.0 million~~$35.8 million. Total exploration costs in 2024 were in the Gulf of Mexico for ~~activities at Chinook #7 (Walker Ridge 425),~~the Orange #1 (Mississippi Canyon 216) and Ocotillo #1 (Mississippi Canyon 40) exploration wells and additional costs related to 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 wereexploration well which encountered 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~~2023 and finished operations in the ~~nine months ended September 30, 2023, total capital expenditures also included acquisition-related capital~~first quarter 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.2024.

Cash Required by Financing Activities

Net cash required by financing activities for the ~~nine~~three months ended ~~September 30, 2023 decreased~~March 31, 2024 increased by ~~$238.2~~$29.5 million compared to the same period in ~~2022.~~2023. In ~~2023,~~2024, 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~~50.0 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~~$0.30 per share ($~~128.7~~45.8 million), withholding tax on stock-based incentive awards ($25.3 million) and distributions to the noncontrolling interest in the Gulf of Mexico ($~~20.1~~23.0 million). In 2023, there were payments of contingent consideration related to prior Gulf of Mexico acquisitions ($47.7 million) as discussed in the “Cash Provided by Operating Activities” section.

Liquidity

At ~~September 30, 2023,~~March 31, 2024, the Company had approximately $1.1 billion of liquidity consisting of ~~$327.8~~$323.4 million in cash and cash equivalents and ~~$795.9~~$796.3 million available on its committed ~~RCF.~~ senior unsecured RCF with a major banking consortium.

The Company’s $800 million senior unsecured RCF expires in November 2027 and as of March 31, 2024, the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF. At March 31, 2024, the interest rate in effect on borrowings under the facility would have been 7.68%. At March 31, 2024, the Company was in compliance with all covenants related to the RCF.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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,~~March 31, 2024, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$124.4~~$98.1 million, the majority of which was held in Canada ($~~76.8~~60.0 million), Mexico ($~~19.1~~15.0 million) and the U.K. ($~~11.7~~9.1 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

(Millions of dollars)

March 31, 2024

December 31, 2023

Working capital

Total current assets

887.0

972.3

Total current assets

Total current liabilities

892.4

1,257.8

Net working capital liability

(5.4)

(285.5)

As of ~~September 30, 2023,~~March 31, 2024, net working capital had a favorable increase of ~~$280.1~~$37.0 million compared to December 31, ~~2022.The~~2023. The favorable increase was primarily attributable to lower other accrued liabilities ($~~306.1~~39.5 million), lower operating lease liabilities ($28.4 million), higher accounts receivable ($12.9 million), and ~~lower accounts payable~~a higher cash balance ($~~93.8~~6.4 million), partially offset by higher accounts ~~receivable~~payable ($~~69.5 million), higher operating lease liabilities ($25.5 million) and a lower cash balance ($164.2~~39.0 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 currentlower operating lease liabilities were ~~associated with scheduled rate increases for a~~primarily due to 2024 payments reducing drilling rig and vessel ~~resulting in additional amounts being reclassified from long-term to current operating~~ lease liabilities. Higher accounts receivable and higher accounts payable were primarily due to the timing of cash receipts and cash payments, respectively.

Capital Employed

A summary of capital employed at ~~September 30, 2023~~March 31, 2024 and December 31, ~~2022~~2023 follows.


		September 30, 2023				December 31, 2022
	March 31, 2024															March 31, 2024						December 31, 2023
(Millions of dollars)	(Millions of dollars)	Amount		%		Amount		%		(Millions of dollars)	Amount			%				Amount					%
Capital employed	Capital employed
Long-term debt	Long-term debt	$	1,576.3	22.8	%	$	1,822.4	26.7	%
Long-term debt
Long-term debt											$	1,328.7		20.0		%		$	1,328.3				19.9	%
Murphy shareholders' equity	Murphy shareholders' equity	5,340.0		77.2	%	4,994.8		73.3	%	Murphy shareholders' equity	5,304.0		80.0		80.0		%		5,362.8		80.1			80.1	%
Total capital employed	Total capital employed	$	6,916.3	100.0	%	$	6,817.2	100.0	%	Total capital employed	$	6,632.7	100.0		100.0		%		$	6,691.1	100.0			100.0	%

At ~~September 30, 2023,~~March 31, 2024, long-term debt of ~~$1,576.3~~$1,328.7 million had ~~decreased~~increased by ~~$246.1~~$0.4 million compared to December 31, ~~2022,~~2023, 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~~7.9 years and a weighted average coupon of 6.2%.

Murphy shareholders’ equity ~~increased~~decreased by ~~$345.2~~$58.8 million in ~~2023~~2024 primarily due to ~~net income earned~~shares repurchased ($~~545.3~~50.0 million, including excise tax), cash dividends paid ($45.8 million) and unrealized foreign currency translation losses ($35.5 million), partially offset by ~~cash dividends paid~~net income earned ($~~128.7~~90.0 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,~~March 31, 2024, 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.~~2023.

Accounting Changes and Recent Accounting Pronouncements

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

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

Other Key Performance Metrics

The Company uses other operational performance and income metrics to review operational performance. 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, and adjusted EBITDA ~~and~~ are non-GAAP financial measures and should not be considered a substitute for ~~Net~~net income (loss) or ~~Cash~~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:~~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


	Three Months Ended March 31,
(Millions of dollars)		2024		2023
Net income attributable to Murphy (GAAP) 1		$	90.0	$	191.6
Discontinued operations loss (income)		0.9		(0.3)
Net income from continuing operations attributable to Murphy		90.9		191.3
Adjustments:
Impairment of assets		34.5		–
Write-off of previously suspended exploration well		26.1		–
Foreign exchange (gain) loss		(10.5)		0.4
Mark-to-market loss on contingent consideration		—		3.9















Total adjustments, before taxes		50.1		4.3
Income tax benefit related to adjustments		(10.2)		(0.9)
Total adjustments after taxes		39.9		3.4
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)		$	130.8	$	194.7

Net income from continuing operations per average diluted share (GAAP)		$	0.60	1.22
Adjusted net income from continuing operations per average diluted share (Non-GAAP)		$	0.85	1.24

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 OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (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:~~Murphy.


		Three Months Ended September 30,				Nine Months Ended September 30,
				Three Months Ended March 31,
				Three Months Ended March 31,
				Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2023		2022		2023		2022		(Millions of dollars)	2024	2023
Net income attributable to Murphy (GAAP) 1	Net income attributable to Murphy (GAAP) 1	$	255.3	$	528.4	$	545.3	$	765.6
Income tax expense	Income tax expense	78.1		159.5		166.8		247.6
Interest expense, net	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
Depreciation, depletion and amortization expense 1
EBITDA attributable to Murphy (Non-GAAP)	EBITDA attributable to Murphy (Non-GAAP)	594.9		933.0		1,431.6		1,681.8
Impairment of asset
Write-off of previously suspended exploration well	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)
Accretion of asset retirement obligations 1
Foreign exchange (gain) loss
Mark-to-market loss on contingent consideration
Discontinued operations loss (income)

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

Adjusted EBITDA attributable to Murphy (Non-GAAP)

Adjusted EBITDA attributable to Murphy (Non-GAAP)

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 OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Outlook

The oil and ~~natural~~ gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile a~~nd is affected~~and are affected by the levels of supply and demand for energy. As discussed in the Results of Operations section discussing revenues, on page 26, ~~lower~~higher average crude oil price during the ~~third~~first quarter of 2024 compared to same period in 2023, directly ~~impacts~~impacted the Company’s product ~~revenue from sales.~~sales revenue.

As of close on ~~October 31, 2023,~~April 30, 2024, forward price curves for existing forward contracts for the remainder of ~~2023~~2024 and ~~2024~~2025 are shown in the table below:


		2023	2024
		2024
		2024
		2024				2025
WTI ($/BBL)	WTI ($/BBL)	81.02	77.93	WTI ($/BBL)	79.92		74.76
NYMEX ($/MMBTU)	NYMEX ($/MMBTU)	3.58	3.61	NYMEX ($/MMBTU)	2.61		3.52
AECO (US$ Equivalent/MCF)	AECO (US$ Equivalent/MCF)	2.22	2.22	AECO (US$ Equivalent/MCF)	1.35		2.43

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~~second quarter of ~~2023,~~2024, production is expected to average between ~~181.5~~176 and ~~189.5~~184 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

The Company’s capital expenditure spend for ~~2023~~2024 is expected to be between ~~$950.0~~$920 million and ~~$1,025.0~~$1,020 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~~2024 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 ana $300 million increase to the original share repurchase program ~~by an additional $300 million,~~announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 ~~million, and~~million. As of March 31, 2024, the Company has ~~$525~~$400 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,~~April 30, 2024, 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~~MCF

Remaining Period

Area

Commodity

Type

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

~~250~~162

C$~~2.35~~2.39

~~10/~~4/1/~~2023~~2024

12/31/~~2023~~2024

Canada

Natural Gas

Fixed price forward sales

US$1.98

~~10/~~4/1/~~2023~~2024

10/31/2024

Canada

Natural Gas

Fixed price forward sales

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

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

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “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; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or 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.~~general, including inflation. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. 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.~~March 31, 2024.

There were no derivative foreign exchange contracts in place at ~~September 30, 2023.~~March 31, 2024.

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,~~March 31, 2024, 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.

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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~~2023 Form 10-K filed on February ~~27, 2023.~~23, 2024. In March 2024, the SEC finalized its climate disclosure rule, SEC Release No. 34-99678, The Enhancement and Standardization of Climate-Related Disclosures for Investors, which requires registrants to provide certain climate-related information in their annual reports. In April 2024, the SEC stayed the climate disclosure rule pending judicial review. The Company has not identified any additional risk factors not previously disclosed in its ~~2022~~2023 Form 10-K ~~report.~~report or noted above.

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
The following table summarizes repurchases of our common stock occurring in the first quarter 2024.


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)
January 1 through January 31, 2024	–	$	–	–	$	450,000
February 1 through February 29, 2024	1,273,245	$	39.25	1,273,245	$	400,000
March 1 through March 31, 2024	–	$	—	–	$	400,000

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

2 In August 2022, the ~~Company’s~~ Board ~~of Directors~~ authorized aan initial share repurchase program of up to $300 million of the Company’s ~~Common Stock.~~common stock. On October 30, 2023, the Board authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million. Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion.

3 Maximum approximate dollar values reported represent amounts at end of the month. ~~During~~Since the ~~nine months ended September 30, 2023, the Company repurchased 1,684,522 shares~~inception of ~~its Common Stock under~~ the share repurchase program, the Company has repurchased 4,684,403 shares of its common stock in open-market transactions for ~~$75.0~~$199.9 million, excluding taxes and fees.

~~Subsequent to the third quarter~~Table 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.Contents

ITEM 5. OTHER INFORMATION

During the three months ended ~~September 30, 2023,~~March 31, 2024, 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 3940 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

3738

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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~~May 2, ~~2023~~2024

(Date)

3839

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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.

*10.35

Form of non-employee director elective restricted stock unit (2021 NED Plan)

*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).

3940


		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)