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, 2021~~March 31, 2022


☐			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. o

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, 2021~~April 30, 2022 was ~~154,459,128~~155,372,135.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


			Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets			2
Consolidated Statements of Operations			3
Consolidated Statements of Comprehensive Income			4
Consolidated Statements of Cash Flows			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Note A – Nature of Business and Interim Financial Statements			7
Note B – New Accounting Principles and Recent Accounting Pronouncements			7
Note C – Revenue from Contracts with Customers			8
Note D – Property, Plant and Equipment			10
Note E – ~~Discontinued Operations and Assets~~Asset s Held for Sale and Discontinued Operations			12
Note F – Financing Arrangements and Debt			12
Note G – Other Financial Information			13
Note H – Employee and Retiree Benefit Plans			14
Note I – Incentive Plans			14
Note J – Earnings Per Share			16
Note K – Income Taxes			16
Note L – Financial Instruments and Risk Management			1716
Note M – Accumulated Other Comprehensive Loss			19
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			20



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2221




Item 3. Quantitative and Qualitative Disclosures About Market Risk			3532
Item 4. Controls and Procedures			3532
Part II – Other Information			3633
Item 1. Legal Proceedings			3633
Item 1A. Risk Factors			3633
~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~			36
Item 6. Exhibits			3633
Signature			3734

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)


(Thousands of dollars)	(Thousands of dollars)	September 30, 2021		December 31, 2020	(Thousands of dollars)	March 31, 2022		December 31, 2021
ASSETS	ASSETS				ASSETS
Current assets	Current assets				Current assets
Cash and cash equivalents	Cash and cash equivalents	$	505,067	310,606	Cash and cash equivalents	$	480,587	521,184
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020		186,683		262,014
Accounts receivable, net					Accounts receivable, net	371,838		258,150
Inventories	Inventories	57,411		66,076	Inventories	59,339		54,198
Prepaid expenses	Prepaid expenses	40,583		33,860	Prepaid expenses	32,585		31,925
Assets held for sale	Assets held for sale	40,987		327,736	Assets held for sale	15,701		15,453
Total current assets	Total current assets	830,731		1,000,292	Total current assets	960,050		880,910
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020		8,112,093		8,269,038
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,660,784 in 2022 and $12,457,851 in 2021					Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,660,784 in 2022 and $12,457,851 in 2021	8,237,743		8,127,852
Operating lease assets	Operating lease assets	918,719		927,658	Operating lease assets	907,504		881,389
Deferred income taxes	Deferred income taxes	442,212		395,253	Deferred income taxes	408,346		385,516
Deferred charges and other assets	Deferred charges and other assets	27,101		28,611	Deferred charges and other assets	28,094		29,273

Total assets	Total assets	$	10,330,856	10,620,852	Total assets	$	10,541,737	10,304,940
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY				LIABILITIES AND EQUITY
Current liabilities	Current liabilities				Current liabilities
Current maturities of long-term debt, finance lease	Current maturities of long-term debt, finance lease	$	646	—	Current maturities of long-term debt, finance lease	$	662	654
Accounts payable	Accounts payable	615,436		407,097	Accounts payable	939,941		623,129
Income taxes payable	Income taxes payable	18,035		18,018	Income taxes payable	21,587		19,951
Other taxes payable	Other taxes payable	26,997		22,498	Other taxes payable	21,415		20,306
Operating lease liabilities	Operating lease liabilities	157,294		103,758	Operating lease liabilities	173,892		139,427
Other accrued liabilities	Other accrued liabilities	316,205		150,578	Other accrued liabilities	441,382		360,859
Liabilities associated with assets held for sale		—		14,372

Total current liabilities	Total current liabilities	1,134,613		716,321	Total current liabilities	1,598,879		1,164,326
Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation	2,613,703		2,988,067	Long-term debt, including finance lease obligation	2,466,114		2,465,414
Asset retirement obligations	Asset retirement obligations	797,627		816,308	Asset retirement obligations	859,335		839,776
Deferred credits and other liabilities	Deferred credits and other liabilities	723,732		680,580	Deferred credits and other liabilities	472,708		570,574
Non-current operating lease liabilities	Non-current operating lease liabilities	781,114		845,088	Non-current operating lease liabilities	752,364		761,162
Deferred income taxes	Deferred income taxes	166,120		180,341	Deferred income taxes	188,047		182,892

Total liabilities	Total liabilities	6,216,909		6,226,705	Total liabilities	6,337,447		5,984,144
Equity	Equity				Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	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 2021 and 195,100,628 shares in 2020		195,101		195,101
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2022 and 195,100,628 shares in 2021					Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2022 and 195,100,628 shares in 2021	195,101		195,101
Capital in excess of par value	Capital in excess of par value	921,227		941,692	Capital in excess of par value	880,537		926,698
Retained earnings	Retained earnings	5,069,578		5,369,538	Retained earnings	5,082,034		5,218,670
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(580,174)		(601,333)	Accumulated other comprehensive loss	(506,355)		(527,711)
Treasury stock	Treasury stock	(1,656,224)		(1,690,661)	Treasury stock	(1,618,478)		(1,655,447)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	3,949,508		4,214,337	Murphy Shareholders' Equity	4,032,839		4,157,311
Noncontrolling interest	Noncontrolling interest	164,439		179,810	Noncontrolling interest	171,451		163,485
Total equity	Total equity	4,113,947		4,394,147	Total equity	4,204,290		4,320,796
Total liabilities and equity	Total liabilities and equity	$	10,330,856	10,620,852	Total liabilities and equity	$	10,541,737	10,304,940

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,
(Thousands of dollars, except per share amounts)	(Thousands of dollars, except per share amounts)	2021		2020	2021		2020	(Thousands of dollars, except per share amounts)		2022		2021
Revenues and other income	Revenues and other income							Revenues and other income
Revenue from sales to customers		$	687,549	425,324	$	2,038,905	1,311,627
(Loss) gain on derivative instruments		(59,164)		(5,290)	(499,794)		319,502
Revenue from production								Revenue from production		$	834,528	592,527
Sales of purchased natural gas								Sales of purchased natural gas		36,846		—
Total revenue from sales to customers								Total revenue from sales to customers		871,374		592,527
Loss on crude contracts								Loss on crude contracts		(320,777)		(214,385)
Gain on sale of assets and other income	Gain on sale of assets and other income	2,315		1,831	21,217		6,006	Gain on sale of assets and other income		2,364		1,843
Total revenues and other income	Total revenues and other income	630,700		421,865	1,560,328		1,637,135	Total revenues and other income		552,961		379,985
Costs and expenses	Costs and expenses							Costs and expenses
Lease operating expenses	Lease operating expenses	130,131		124,491	403,708		478,283	Lease operating expenses		136,825		147,164
Severance and ad valorem taxes	Severance and ad valorem taxes	11,670		6,781	32,215		22,645	Severance and ad valorem taxes		14,635		9,231
Transportation, gathering and processing	Transportation, gathering and processing	44,588		41,322	137,196		126,779	Transportation, gathering and processing		46,923		42,912
Costs of purchased natural gas								Costs of purchased natural gas		33,665		—
Exploration expenses, including undeveloped lease amortization	Exploration expenses, including undeveloped lease amortization	24,517		12,092	49,840		61,686	Exploration expenses, including undeveloped lease amortization		47,566		11,780
Selling and general expenses	Selling and general expenses	27,210		28,509	85,826		104,381	Selling and general expenses		33,529		29,503
Restructuring expenses		—		4,982	—		46,379

Depreciation, depletion and amortization	Depreciation, depletion and amortization	189,806		231,603	615,372		769,151	Depreciation, depletion and amortization		164,124		198,278
Accretion of asset retirement obligations	Accretion of asset retirement obligations	12,198		10,778	34,854		31,213	Accretion of asset retirement obligations		11,876		10,492
Impairment of assets	Impairment of assets	—		219,138	171,296		1,206,284	Impairment of assets		—		171,296
Other (benefit) expense		(32,791)		20,224	58,616		(2,957)
Other operating expense								Other operating expense		105,942		21,079
Total costs and expenses	Total costs and expenses	407,329		699,920	1,588,923		2,843,844	Total costs and expenses		595,085		641,735
Operating income (loss) from continuing operations		223,371		(278,055)	(28,595)		(1,206,709)
Operating loss from continuing operations								Operating loss from continuing operations		(42,124)		(261,750)
Other income (loss)	Other income (loss)							Other income (loss)
Interest income and other (loss)		(1,593)		(5,177)	(11,459)		(10,107)
Other expense								Other expense		(2,495)		(5,341)
Interest expense, net	Interest expense, net	(46,925)		(45,182)	(178,399)		(124,877)	Interest expense, net		(37,277)		(88,100)
Total other loss	Total other loss	(48,518)		(50,359)	(189,858)		(134,984)	Total other loss		(39,772)		(93,441)
Income (loss) from continuing operations before income taxes		174,853		(328,414)	(218,453)		(1,341,693)
Income tax expense (benefit)		36,838		(62,584)	(62,498)		(248,890)
Income (loss) from continuing operations		138,015		(265,830)	(155,955)		(1,092,803)
(Loss) from discontinued operations, net of income taxes		(706)		(778)	(600)		(6,907)
Net income (loss) including noncontrolling interest		137,309		(266,608)	(156,555)		(1,099,710)
Less: Net income (loss) attributable to noncontrolling interest		28,853		(23,055)	85,509		(122,869)
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY		$	108,456	(243,553)	$	(242,064)	(976,841)
INCOME (LOSS) PER COMMON SHARE – BASIC
Loss from continuing operations before income taxes								Loss from continuing operations before income taxes		(81,896)		(355,191)
Income tax benefit								Income tax benefit		(16,961)		(88,159)
Loss from continuing operations								Loss from continuing operations		(64,935)		(267,032)
(Loss) income from discontinued operations, net of income taxes								(Loss) income from discontinued operations, net of income taxes		(551)		208
Net loss including noncontrolling interest								Net loss including noncontrolling interest		(65,486)		(266,824)
Less: Net income attributable to noncontrolling interest								Less: Net income attributable to noncontrolling interest		47,850		20,614
NET LOSS ATTRIBUTABLE TO MURPHY								NET LOSS ATTRIBUTABLE TO MURPHY		$	(113,336)	(287,438)
LOSS PER COMMON SHARE – BASIC								LOSS PER COMMON SHARE – BASIC
Continuing operations	Continuing operations	$	0.70	(1.58)	$	(1.57)	(6.31)	Continuing operations		$	(0.73)	(1.87)
Discontinued operations	Discontinued operations	—		(0.01)	—		(0.05)	Discontinued operations		—		—
Net income (loss)		$	0.70	(1.59)	$	(1.57)	(6.36)
INCOME (LOSS) PER COMMON SHARE – DILUTED
Net loss								Net loss		$	(0.73)	(1.87)
LOSS PER COMMON SHARE – DILUTED								LOSS PER COMMON SHARE – DILUTED
Continuing operations	Continuing operations	$	0.70	(1.58)	$	(1.57)	(6.31)	Continuing operations		$	(0.73)	(1.87)
Discontinued operations	Discontinued operations	—		(0.01)	—		(0.05)	Discontinued operations		—		—
Net income (loss)		$	0.70	(1.59)	$	(1.57)	(6.36)
Net loss								Net loss		$	(0.73)	(1.87)
Cash dividends per Common share	Cash dividends per Common share	$	0.125	0.125	0.375		0.500	Cash dividends per Common share		0.15		0.125

Average Common shares outstanding (thousands)	Average Common shares outstanding (thousands)							Average Common shares outstanding (thousands)
Basic	Basic	154,439		153,596	154,239		153,480	Basic		154,916		153,953
Diluted	Diluted	155,932		153,596	154,239		153,480	Diluted		154,916		153,953

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,
(Thousands of dollars) 2021 2020 2021 2020
Net income (loss) including noncontrolling interest $ 137,309 (266,608) $ (156,555) (1,099,710)
Other comprehensive (loss) income, net of tax
Net (loss) gain from foreign currency translation (31,308) 28,323 6,534 (39,520)
Retirement and postretirement benefit plans 4,653 3,726 12,935 (45,219)
Deferred loss on interest rate hedges reclassified to interest expense — 297 1,690 905
Other comprehensive (loss) income (26,655) 32,346 21,159 (83,834)
COMPREHENSIVE INCOME (LOSS) $ 110,654 (234,262) $ (135,396) (1,183,544)


	Three Months Ended March 31,
(Thousands of dollars)		2022		2021
Net loss including noncontrolling interest		$	(65,486)	(266,824)
Other comprehensive income, net of tax
Net gain from foreign currency translation		18,020		19,897
Retirement and postretirement benefit plans		3,336		4,136
Deferred loss on interest rate hedges reclassified to interest expense		—		1,690

Other comprehensive income		21,356		25,723
Comprehensive loss including noncontrolling interest		(44,130)		(241,101)
Less: Comprehensive income attributable to noncontrolling interest		47,850		20,614
COMPREHENSIVE LOSS ATTRIBUTABLE TO MURPHY		$	(91,980)	(261,715)

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,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	(Thousands of dollars)	2022		2021
Operating Activities	Operating Activities				Operating Activities
Net income (loss) including noncontrolling interest		$	(156,555)	(1,099,710)
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities
Loss from discontinued operations		600		6,907
Net loss including noncontrolling interest					Net loss including noncontrolling interest	$	(65,486)	(266,824)
Adjustments to reconcile net loss to net cash provided by continuing operations activities					Adjustments to reconcile net loss to net cash provided by continuing operations activities
Loss (income) from discontinued operations					Loss (income) from discontinued operations	551		(208)
Depreciation, depletion and amortization	Depreciation, depletion and amortization	615,372		769,151	Depreciation, depletion and amortization	164,124		198,278
Dry hole and previously suspended exploration costs		17,899		8,255
Unsuccessful exploration well costs and previously suspended exploration costs					Unsuccessful exploration well costs and previously suspended exploration costs	32,831		717
Amortization of undeveloped leases	Amortization of undeveloped leases	13,872		21,951	Amortization of undeveloped leases	4,198		4,602
Accretion of asset retirement obligations	Accretion of asset retirement obligations	34,854		31,213	Accretion of asset retirement obligations	11,876		10,492
Deferred income tax benefit					Deferred income tax benefit	(20,253)		(88,867)
Mark to market loss on contingent consideration					Mark to market loss on contingent consideration	98,126		14,923
Mark to market loss on crude contracts					Mark to market loss on crude contracts	188,509		153,505
Long-term non-cash compensation					Long-term non-cash compensation	17,288		12,124
Impairment of assets	Impairment of assets	171,296		1,206,284	Impairment of assets	—		171,296
Noncash restructuring expense		—		17,565
Deferred income tax (benefit) expense		(65,149)		(231,748)

Mark to market loss (gain) on contingent consideration		105,111		(29,476)
Mark to market loss (gain) on derivative instruments		228,497		(104,463)
Long-term non-cash compensation		42,080		35,200
Net decrease (increase) in noncash working capital		117,330		(26,261)

Net (increase) in noncash working capital					Net (increase) in noncash working capital	(80,922)		(9,052)
Other operating activities, net	Other operating activities, net	(33,924)		(26,837)	Other operating activities, net	(12,512)		36,780
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	1,091,283		578,031	Net cash provided by continuing operations activities	338,330		237,766
Investing Activities	Investing Activities				Investing Activities
Property additions and dry hole costs	Property additions and dry hole costs	(564,230)		(648,725)	Property additions and dry hole costs	(244,908)		(240,545)
Property additions for King's Quay FPS	Property additions for King's Quay FPS	(17,734)		(74,936)	Property additions for King's Quay FPS	—		(17,734)

Proceeds from sales of property, plant and equipment	Proceeds from sales of property, plant and equipment	270,038		—	Proceeds from sales of property, plant and equipment	—		268,023
Net cash required by investing activities		(311,926)		(723,661)
Net cash (required) provided by investing activities					Net cash (required) provided by investing activities	(244,908)		9,744
Financing Activities	Financing Activities				Financing Activities
Borrowings on revolving credit facility	Borrowings on revolving credit facility	165,000		450,000	Borrowings on revolving credit facility	—		140,000
Repayment of revolving credit facility	Repayment of revolving credit facility	(365,000)		(250,000)	Repayment of revolving credit facility	—		(340,000)
Retirement of debt	Retirement of debt	(726,358)		(12,225)	Retirement of debt	—		(576,358)
Debt issuance, net of cost	Debt issuance, net of cost	541,913		(613)	Debt issuance, net of cost	—		541,980
Early redemption of debt cost	Early redemption of debt cost	(36,756)		—	Early redemption of debt cost	—		(34,177)
Distributions to noncontrolling interest	Distributions to noncontrolling interest	(100,880)		(43,673)	Distributions to noncontrolling interest	(39,884)		(36,006)
Contingent consideration payment					Contingent consideration payment	(55,169)		—
Cash dividends paid	Cash dividends paid	(57,896)		(76,790)	Cash dividends paid	(23,300)		(19,287)
Withholding tax on stock-based incentive awards	Withholding tax on stock-based incentive awards	(4,973)		(7,094)	Withholding tax on stock-based incentive awards	(15,421)		(3,794)

Capital lease obligation payments	Capital lease obligation payments	(643)		(514)	Capital lease obligation payments	(158)		(178)

Net cash (required) provided by financing activities		(585,593)		59,091
Cash Flows from Discontinued Operations 1
Operating activities		—		(1,202)
Investing activities		—		4,494
Financing activities		—		—
Net cash provided by discontinued operations		—		3,292

Net cash (required) by financing activities					Net cash (required) by financing activities	(133,932)		(327,820)

Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	697		(585)	Effect of exchange rate changes on cash and cash equivalents	(87)		574
Net increase (decrease) in cash and cash equivalents		194,461		(87,124)
Net (decrease) in cash and cash equivalents					Net (decrease) in cash and cash equivalents	(40,597)		(79,736)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period	310,606		306,760	Cash and cash equivalents at beginning of period	521,184		310,606
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	505,067	219,636	Cash and cash equivalents at end of period	$	480,587	230,870

1 ~~Net cash provided by discontinued operations is not part of the cash flow reconciliation.~~ 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 September 30,			Nine Months Ended September 30,				Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021		2020	(Thousands of dollars)		2022		2021
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	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 at September 30, 2021 and 195,100,628 shares at September 30, 2020
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2022 and 195,100,628 shares at March 31, 2021								Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2022 and 195,100,628 shares at March 31, 2021
Balance at beginning of period	Balance at beginning of period	195,101		195,101	195,101		195,089	Balance at beginning of period		195,101		195,101
Exercise of stock options	Exercise of stock options	—		—	—		12	Exercise of stock options		—		—
Balance at end of period	Balance at end of period	195,101		195,101	195,101		195,101	Balance at end of period		195,101		195,101
Capital in Excess of Par Value	Capital in Excess of Par Value							Capital in Excess of Par Value
Balance at beginning of period	Balance at beginning of period	915,181		931,429	941,692		949,445	Balance at beginning of period		926,698		941,692
Exercise of stock options, including income tax benefits	Exercise of stock options, including income tax benefits	(35)		—	(661)		(156)	Exercise of stock options, including income tax benefits		(7,220)		(39)
Restricted stock transactions and other	Restricted stock transactions and other	(402)		(409)	(38,749)		(33,649)	Restricted stock transactions and other		(45,169)		(33,000)
Share-based compensation	Share-based compensation	6,483		5,298	18,945		20,678	Share-based compensation		6,228		5,650

Balance at end of period	Balance at end of period	921,227		936,318	921,227		936,318	Balance at end of period		880,537		914,303
Retained Earnings	Retained Earnings							Retained Earnings
Balance at beginning of period	Balance at beginning of period	4,980,428		5,823,426	5,369,538		6,614,304	Balance at beginning of period		5,218,670		5,369,538
Net (loss) attributable to Murphy		108,456		(243,553)	(242,064)		(976,841)
Net loss attributable to Murphy								Net loss attributable to Murphy		(113,336)		(287,438)

Cash dividends	Cash dividends	(19,306)		(19,200)	(57,896)		(76,790)	Cash dividends		(23,300)		(19,287)
Balance at end of period	Balance at end of period	5,069,578		5,560,673	5,069,578		5,560,673	Balance at end of period		5,082,034		5,062,813
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss							Accumulated Other Comprehensive Loss
Balance at beginning of period	Balance at beginning of period	(553,519)		(690,341)	(601,333)		(574,161)	Balance at beginning of period		(527,711)		(601,333)
Foreign currency translation gain (loss), net of income taxes		(31,308)		28,323	6,534		(39,520)
Foreign currency translation gain, net of income taxes								Foreign currency translation gain, net of income taxes		18,020		19,897
Retirement and postretirement benefit plans, net of income taxes	Retirement and postretirement benefit plans, net of income taxes	4,653		3,726	12,935		(45,219)	Retirement and postretirement benefit plans, net of income taxes		3,336		4,136
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	—		297	1,690		905	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes		—		1,690

Balance at end of period	Balance at end of period	(580,174)		(657,995)	(580,174)		(657,995)	Balance at end of period		(506,355)		(575,610)
Treasury Stock	Treasury Stock							Treasury Stock
Balance at beginning of period	Balance at beginning of period	(1,656,591)		(1,691,070)	(1,690,661)		(1,717,217)	Balance at beginning of period		(1,655,447)		(1,690,661)

Awarded restricted stock, net of forfeitures	Awarded restricted stock, net of forfeitures	343		409	33,888		26,556	Awarded restricted stock, net of forfeitures		32,297		29,206
Exercise of stock options	Exercise of stock options	24		—	549		—	Exercise of stock options		4,672		39
Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost		(1,656,224)		(1,690,661)	(1,656,224)		(1,690,661)
Balance at end of period – 39,730,079 shares of Common Stock in 2022 and 40,784,118 shares of Common Stock in 2021, at cost								Balance at end of period – 39,730,079 shares of Common Stock in 2022 and 40,784,118 shares of Common Stock in 2021, at cost		(1,618,478)		(1,661,416)
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	3,949,508		4,343,436	3,949,508		4,343,436	Murphy Shareholders’ Equity		4,032,839		3,935,191
Noncontrolling Interest	Noncontrolling Interest							Noncontrolling Interest
Balance at beginning of period	Balance at beginning of period	161,228		204,937	179,810		337,151	Balance at beginning of period		163,485		179,810

Net income (loss) attributable to noncontrolling interest		28,853		(23,055)	85,509		(122,869)
Net income attributable to noncontrolling interest								Net income attributable to noncontrolling interest		47,850		20,614
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(25,642)		(11,273)	(100,880)		(43,673)	Distributions to noncontrolling interest owners		(39,884)		(36,006)
Balance at end of period	Balance at end of period	164,439		170,609	164,439		170,609	Balance at end of period		171,451		164,418
Total Equity	Total Equity	$	4,113,947	4,514,045	$	4,113,947	4,514,045	Total Equity		$	4,204,290	4,099,609

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 ~~(Murphy/ Company)~~(the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.

Note A – Nature of Business and Interim Financial Statements

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas exploration and production company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.

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 2 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 because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of ~~September 30, 2021,~~March 31, 2022, our maximum exposure to loss was ~~$3.4~~$3.2 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.

INTERIM FINANCIAL STATEMENTS – In the opinion of the Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting 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 ~~2020~~2021 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, 2021~~March 31, 2022 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Income Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. The Company adopted this guidance in the first quarter of 2021 and it did not have a material impact on its consolidated financial statements.

Recent Accounting Pronouncements

None affecting the Company.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 2 key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from 3 primary revenue streams: crude oil and condensate, natural gas liquids, 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 in MP GOM as prescribed by ASC 810-10-45.

U.S. - In the United States, 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 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 physical forward sales fixed-price contracts. For the ~~Offshore~~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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)

Disaggregation of Revenue

The Company reviews performance based on 2 key geographical segments and between onshore and offshore sources of revenue within these geographies.

For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2022, and 2021, the Company recognized ~~$687.5~~$871.4 million and ~~$2,038.9~~$592.5 million, respectively, from ~~contracts with~~total revenue from sales to customers, for the sales of oil, natural gas liquids and natural gas. For the three-month and nine-month periods ended September 30, 2020, the Company recognized $425.3 million and $1,311.6 million, respectively, from ~~contracts with customers for the~~ sales of oil, natural gas liquids and natural gas.

Three Months Ended
September 30, Nine Months Ended
September 30,
(Thousands of dollars) 2021 2020 2021 2020
Net crude oil and condensate revenue
United States Onshore $ 167,010 86,498 464,767 272,284
                      Offshore 340,001 216,918 1,079,418 714,143
Canada     Onshore 29,110 32,358 89,708 67,268
Offshore 20,499 19,173 70,333 54,864
Other — — — 1,806
Total crude oil and condensate revenue 556,620 354,947 1,704,226 1,110,365
Net natural gas liquids revenue
United States Onshore 16,356 6,766 33,480 16,145
Offshore 11,046 4,765 31,866 13,255
Canada Onshore 4,501 2,780 11,728 6,090
Total natural gas liquids revenue 31,903 14,311 77,074 35,490
Net natural gas revenue
United States Onshore 11,127 4,529 24,442 14,177
Offshore 17,444 9,827 56,855 35,487
Canada    Onshore 70,455 41,710 176,308 116,108
Total natural gas revenue 99,026 56,066 257,605 165,772
Total revenue from contracts with customers 687,549 425,324 2,038,905 1,311,627
(Loss) gain on derivative instruments (59,164) (5,290) (499,794) 319,502
Gain on sale of assets and other income 2,315 1,831 21,217 6,006
Total revenue and other income $ 630,700 421,865 1,560,328 1,637,135
For the three-month periods ended March 31, 2022, and 2021, the Company recognized $834.5 million and $592.5 million, respectively, from sales of oil, natural gas liquids and natural gas from production.


		Three Months Ended March 31,
(Thousands of dollars)			2022		2021
Net crude oil and condensate revenue
United States	Onshore		$	171,696	114,490
	Offshore		465,621		328,341
Canada	Onshore		36,697		29,903
	Offshore		28,832		18,062

Total crude oil and condensate revenue			702,846		490,796

Net natural gas liquids revenue
United States	Onshore		16,685		7,528
	Offshore		13,979		10,054
Canada	Onshore		4,867		3,987
Total natural gas liquids revenue			35,531		21,569

Net natural gas revenue
United States	Onshore		11,369		6,443
	Offshore		26,201		22,138
Canada	Onshore		58,581		51,581
Total natural gas revenue			96,151		80,162

Revenue from production			834,528		592,527



Sales of purchased natural gas1			36,846		—

Total revenue from sales to customers			871,374		592,527

Loss on crude contracts			(320,777)		(214,385)
Gain on sale of assets and other income			2,364		1,843
Total revenues and other income			$	552,961	379,985

1 Sales of purchase natural gas are associated with Canada Onshore.

In 2022, the Company included additional line items on the face of the Consolidated Statements of Operations to report Sales of purchased natural gas and Costs of purchased natural gas. Sales and purchases of natural gas are reported on a gross basis when Murphy takes control of the products and has risks and rewards of ownership.

Contract Balances and Asset Recognition

As of ~~September 30, 2021,~~March 31, 2022, and December 31, ~~2020,~~2021, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were ~~$144.0~~$258.6 million and ~~$135.2~~$169.8 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as ~~at September 30, 2021.~~of March 31, 2022.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers(Contd.)

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 to obtain a contract with a customer.

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note C – Revenue from Contracts with Customers(Contd.)~~

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~~Company’s long-term strategy.

As of ~~September 30, 2021,~~March 31, 2022, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:

Current Long-Term Contracts Outstanding at ~~September 30, 2021~~March 31, 2022

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

~~Oil~~

~~Q4 2021~~

~~Fixed quantity delivery in Eagle Ford~~

~~17,000 BOED~~

~~U.S.~~

Natural Gas and NGL

Q1 2023

Deliveries from dedicated acreage in Eagle Ford

As produced

~~Canada~~

~~Natural Gas~~

~~Q4 2021~~

~~Contracts to sell natural gas at USD index pricing~~

~~10 MMCFD~~

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD index pricing

8 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at CAD fixed prices

5 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD fixed pricing

20 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at USD index pricing

25 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at CAD fixed prices

38 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD index pricing

31 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

100 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

34 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD fixed pricing

15 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCFD

Canada

NGL

Q3 2023

Contracts to sell natural gas liquids at CAD pricing

952 BOED

1 ~~These contracts are scheduled to commence after the balance sheet date, at various dates between Q4 2021 and Q1 2022.~~

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

Note D – Property, Plant and Equipment

Exploratory Wells

Under 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 is making sufficient progress assessing the reserves and the economic and operating viability of the project.

As of ~~September 30, 2021,~~March 31, 2022, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of ~~$186.6~~$172.7 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Property, Plant and Equipment (Contd.)


(Thousands of dollars)	(Thousands of dollars)	2021		2020	(Thousands of dollars)	2022		2021
Beginning balance at January 1	Beginning balance at January 1	$	181,616	217,326	Beginning balance at January 1	$	179,481	181,616
Additions pending the determination of proved reserves	Additions pending the determination of proved reserves	5,007		9,941	Additions pending the determination of proved reserves	3,698		785

Capitalized exploratory well costs charged to expense	Capitalized exploratory well costs charged to expense	—		(39,408)	Capitalized exploratory well costs charged to expense	(10,473)		—
Balance at September 30		$	186,623	187,859
Balance at March 31					Balance at March 31	$	172,706	182,401

The capitalized well costs charged to expense during ~~2020~~2022 represent ~~a charge for asset impairments (see below).~~expenditures related to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil. There were no hydrocarbons found in this well.

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,								March 31,
		2021				2020				2022				2021

(Thousands of dollars)	(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount	No. of Wells	No. of Projects	(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:								Aging of capitalized well costs:
Zero to one year	Zero to one year	$	3,297	2	2	8,000	1	—	Zero to one year	$	2,810	2	2	—	—	—
One to two years	One to two years	—		—	—	54,334	5	5	One to two years	—		—	—	23,514	3	3
Two to three years	Two to three years	53,078		5	5	—	—	—	Two to three years	23,667		3	3	30,562	2	2
Three years or more	Three years or more	130,248		6	—	125,525	6	—	Three years or more	146,229		8	2	128,325	6	—
		$	186,623	13	7	187,859	12	5		$	172,706	13	7	182,401	11	5

Of the ~~$183.3~~$169.9 million of exploratory well costs capitalized more than one year at ~~September 30, 2021, $92.3~~March 31, 2022, $94.0 million is in Vietnam, ~~$45.0~~$47.6 million is in the U.S., ~~$25.9 million is in Brunei,~~ $15.3 million is in Mexico, $8.2 million is in Brunei, and $4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Impairments

~~During~~There were no impairments in the first quarter of 2022. In the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with ~~the~~ partners, of operating and production plans. Later in 2021, the Company acquired an additional 7.525% working interest at Terra Nova following a commercial agreement to sanction an asset life extension project.

In 2020, declines in future oil and natural gas prices (principally driven by reduced demand from the COVID-19 pandemic) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $1,206.3 million to reduce the carrying values to their estimated fair values at select properties.

~~The fair values~~Divestments

There were ~~determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants~~no divestments in the ~~applicable region.~~

~~The following table reflects the recognized impairments for the nine months ended September 30, 2021 and 2020.~~

Nine Months Ended
September 30,
(Thousands of dollars) 2021 2020
U.S. $ — 1,152,515
Canada 171,296 —
Other Foreign — 39,709
Corporate — 14,060
$ 171,296 1,206,284

~~Divestments~~

first quarter of 2022. During the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which ~~reimburses~~reimbursed the Company for previously incurred capital expenditures.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Assets Held for Sale and Discontinued Operations

The Company has accounted for its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were as follows:


		Three Months Ended September 30,			Nine Months Ended September 30,				Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021		2020	(Thousands of dollars)		2022		2021
Revenues	Revenues	$	144	—	$	801	4,074	Revenues		$	10	44
Costs and expenses	Costs and expenses							Costs and expenses

Other costs and expenses (benefits)	Other costs and expenses (benefits)	850		778	1,401		10,981	Other costs and expenses (benefits)		561		(164)
(Loss) income before taxes	(Loss) income before taxes	(706)		(778)	(600)		(6,907)	(Loss) income before taxes		(551)		208
Income tax expense	Income tax expense	—		—	—		—	Income tax expense		—		—
(Loss) income from discontinued operations	(Loss) income from discontinued operations	$	(706)	(778)	$	(600)	(6,907)	(Loss) income from discontinued operations		$	(551)	208

As of ~~September 30,~~March 31, 2022 and December 31, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the net property, plant and equipment of CA-2 project in Brunei and the Company’s ~~office building in El Dorado, Arkansas. As of June 30, 2021, the CA-1 asset in Brunei is no longer being marketed for sale.~~

As of December 31, 2020, assets held for sale included the King’s Quay Floating Production System (FPS) of $250.1 million (sold in March 2021), the Brunei exploration and production properties, and the Company’sformer headquarters office building in El Dorado, Arkansas.

(Thousands of dollars) September 30,
2021 December 31,
2020
Current assets
Cash $ — 10,185
Inventories — 406
Property, plant, and equipment, net 40,987 307,704
Deferred income taxes and other assets — 9,441
Total current assets associated with assets held for sale $ 40,987 327,736
Current liabilities
Accounts payable $ — 5,306
Other accrued liabilities — 45
Current maturities of long-term debt (finance lease) — 737
Taxes payable — 1,510
Long-term debt (finance lease) — 6,513
Asset retirement obligation — 261
Total current liabilities associated with assets held for sale $ — 14,372


(Thousands of dollars)	March 31, 2022		December 31, 2021
Current assets




Property, plant, and equipment, net	15,701		15,453


Total current assets associated with assets held for sale	$	15,701	15,453

Note F – Financing Arrangements and Debt

As of ~~September 30, 2021,~~March 31, 2022, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At ~~September 30, 2021,~~March 31, 2022, the Company had no outstanding borrowings under the RCF and $31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At ~~September 30, 2021,~~March 31, 2022, the interest rate in effect on borrowings under the facility was ~~1.78%~~2.15%. At ~~September 30,~~March 31, 2022 and 2021, the Company was in compliance with all covenants related to the RCF.

In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022; collectively

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note F – Financing Arrangements and Debt~~ ~~(Contd.)~~

the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the ~~nine~~three months ended ~~September 30,~~March 31, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the ~~nine~~three months ended ~~September 30, 2021.~~

In August 2021, the Company redeemed $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30,March 31, 2021.

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

~~Subsequent to quarter end,~~On May 2, 2022, the Company issued a notice of partial redemption with respect to ~~$150.0~~$200.0 million aggregate principal amount of its 6.875% senior notes due 2024 ~~(2024~~(the Notes). The Company will redeem the ~~2024~~ Notes at the applicable redemption price set forth in the indenture governing the ~~2024~~ Notes, plus accrued and unpaid interest, if any, to but, not including, the date of redemption. The redemption date of the ~~2024~~ Notes will be ~~December~~June 2, ~~2021.~~2022.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

Nine Months Ended
September 30,
(Thousands of dollars) 2021 2020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
Decrease in accounts receivable ¹ $ 75,100 251,706
Decrease in inventories 9,718 4,747
(Increase) in prepaid expenses (6,682) (17,400)
Increase (decrease) in accounts payable and accrued liabilities ¹ 40,687 (264,078)
(Decrease) in income taxes payable (1,493) (1,236)
Net (increase) decrease in noncash operating working capital $ 117,330 (26,261)
Supplementary disclosures:
Cash income taxes paid, net of refunds $ 1,685 (12,559)
Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020 127,793 139,651
Non-cash investing activities:
Asset retirement costs capitalized ² $ 36,300 6,342
Decrease in capital expenditure accrual 31,301 74,742


	Three Months Ended March 31,
(Thousands of dollars)	2022		2021
Net decrease (increase) in operating working capital, excluding cash and cash equivalents:
(Increase) in accounts receivable ¹	$	(117,928)	(16,954)
(Increase) decrease in inventories	(4,541)		392
(Increase) in prepaid expenses	(515)		(3,652)
Increase in accounts payable and accrued liabilities ¹	40,426		11,810
Increase (decrease) in income taxes payable	1,636		(648)
Net (increase) in noncash operating working capital	$	(80,922)	(9,052)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	103	720
Interest paid, net of amounts capitalized of $5.3 million in 2022 and $3.3 million in 2021	40,181		44,577

Non-cash investing activities:
Asset retirement costs capitalized 2	$	3,889	6,390
(Increase) decrease in capital expenditure accrual	(49,352)		13,617

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

2 Excludes non-cash capitalized cost offset by Terra Nova impairment of $74.4 million in the first quarter of 2021 and a gain in other operating income of $71.8 million following a commercial agreement to sanction an asset life extension project at Terra Nova in the third quarter of 2021, which extended the life of Terra Nova by approximately 10 years.2021.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally 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 are based on 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, 2021~~March 31, 2022 and ~~2020.~~2021.


		Three Months Ended September 30,						Three Months Ended March 31,
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021	2020	(Thousands of dollars)	2022		2021	2022	2021
Service cost	Service cost	$	1,770	1,664	328	342	Service cost	$	2,129	1,768	292	326
Interest cost	Interest cost	4,258		4,827	521	612	Interest cost	5,243		4,286	574	521
Expected return on plan assets	Expected return on plan assets	(6,038)		(5,773)	—	—	Expected return on plan assets	(8,138)		(6,133)	—	—
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	155		149	—	—	Amortization of prior service cost (credit)	600		156	(133)	—
Recognized actuarial loss	Recognized actuarial loss	5,269		5,690	(8)	(24)	Recognized actuarial loss	3,822		5,279	(77)	(7)
Net periodic benefit expense	Net periodic benefit expense	$	5,414	6,557	841	930	Net periodic benefit expense	$	3,656	5,356	656	840

		Nine Months Ended September 30,
		Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2021		2020	2021	2020
Service cost		$	5,306	5,996	981	1,235
Interest cost		12,844		16,381	1,563	2,200
Expected return on plan assets		(18,326)		(18,414)	—	—
Amortization of prior service cost (credit)		467		515	—	—
Recognized actuarial loss		15,829		14,223	(23)	(24)
Net periodic benefit expense		$	16,120	18,701	2,521	3,411
Other - curtailment		—		586	—	(1,825)
Other - special termination benefits		—		8,435	—	—
Total net periodic benefit expense		$	16,120	27,722	2,521	1,586

The components of net periodic benefit expense, other than the service cost, ~~curtailment and special termination benefits components,~~ are ~~included~~recorded in Other expense in the ~~line item “Interest and other income (loss)” in~~ Consolidated Statements of Operations.

During the ~~nine-month~~three-month period ended ~~September 30, 2021,~~March 31, 2022, the Company made contributions of ~~$31.0~~$8.7 million to its defined benefit pension and postretirement benefit plans. Remaining funding in ~~2021~~2022 for the Company’s defined benefit pension and postretirement plans is anticipated to be ~~$10.9~~$34.4 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~~On December 7, 2021, the Board approved the replacement of the 2017 Annual Incentive Plan (2017 Annual Plan) with the Murphy Oil Corporation Annual Incentive Plan (AIP) effective as of January 1, 2022.The new AIP can be found as an exhibit to the Company’s 2021 Form 10-K filed on February 25, 2022 and will remain in effect until such time as the Plan is terminated by the Board. The AIP authorizes the Executive 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 ~~2017 Annual Plan~~AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5000000 shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Incentive Plans(Contd.)

During the first ~~nine~~three months of ~~2021,~~2022, the Committee granted the following awards from the 2020 Long-Term Plan:

2020 Long-Term Incentive 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

Performance Based RSUs 1

1,156,800

February 2, 2021

16.03

Monte Carlo at Grant Date

Performance Based RSUs 1

580,600

February 1, 2022

47.37

Monte Carlo

Time Based RSUs 2

385,600

February 2, 2021

12.30

Average Stock Price at Grant Date

Time Based RSUs 2

273,400

February 1, 2022

32.12

Average Stock Price

Cash Settled RSUs 3

1,022,700

February 2, 2021

12.30

Average Stock Price at Grant Date

Cash Settled RSUs 3

674,300

February 1, 2022

32.12

Average Stock Price

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

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

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

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

At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan 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 NED Plan and the 2018 NED Plan. All awards on or after May 12, 2021, ~~will be~~were made under the 2021 NED Plan.

During the first ~~nine~~three months of ~~2021,~~2022, the Committee granted the following awards to Non-Employee Directors:

~~2018~~2021 Stock Plan for Non-Employee Directors

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

182,652

February 3, 2021

13.14

Closing Stock Price at Grant Date

Time Based RSUs 1

73,092

February 2, 2022

32.84

Closing Stock Price

1 Non-employee directors time-based RSUs are scheduled to vest in February ~~2022.~~

~~2021 Stock Plan for Non-Employee Directors~~

Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology
Time Based RSUs 1
5,655 June 10, 2021 $ 23.58 Closing Stock Price at Grant Date

1 ~~Non-employee directors time-based RSUs are scheduled to vest in February 2022.~~2023.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

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,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	(Thousands of dollars)	2022		2021
Compensation charged against income before tax benefit	Compensation charged against income before tax benefit	$	29,145	17,542	Compensation charged against income before tax benefit	$	13,962	8,196
Related income tax benefit recognized in income	Related income tax benefit recognized in income	4,120		2,278	Related income tax benefit recognized in income	2,272		1,165

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 (Contd.)

Note J – Earnings Per Share

Net ~~(loss) income~~loss attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month ~~and nine-month~~ periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The following table reports the weighted-average shares outstanding used for these computations.


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended March 31,
(Weighted-average shares)	(Weighted-average shares)	2021	2020	2021	2020	(Weighted-average shares)		2022	2021
Basic method	Basic method	154,439,313	153,596,109	154,239,440	153,479,654	Basic method		154,916,004	153,952,552
Dilutive stock options and restricted stock units ¹	Dilutive stock options and restricted stock units ¹	1,492,949	—	—	—	Dilutive stock options and restricted stock units ¹		—	—
Diluted method	Diluted method	155,932,262	153,596,109	154,239,440	153,479,654	Diluted method		154,916,004	153,952,552

1 Due to a net loss recognized by the Company for the ~~nine-month period ended September 30, 2021 and the~~ three-month ~~and nine-month~~ periods ended ~~September 30, 2020,~~March 31, 2022 and 2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

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,
2021 2020 2021 2020
Antidilutive stock options excluded from diluted shares 1,316,222 2,111,068 1,502,758 2,305,973
Weighted average price of these options $ 34.42 $ 38.54 $ 34.97 $ 40.15

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, 2022 and 2021, ~~and 2020,~~ the Company’s effective income tax rates were as follows:

2021 2020
Three months ended September 30, 21.1% 19.1%
Nine months ended September 30, 28.6% 18.6%


	2022	2021

Three months ended March 31,	20.7%	24.8%

The effective tax rate for the three-month period ended ~~September 30, 2021~~March 31, 2022 was ~~above~~below the U.S. statutory tax rate of 21% primarily due to exploration expenses in certain foreign jurisdictions in which no income ~~generated in Canada, which has a higher~~ tax ~~rate,~~benefit is currently available, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP ~~GOM, which has the impact of decreasing the effective tax rate on income.~~GOM.

The effective tax rate for the three-month period ended September 30, 2020 was below the statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM.

~~The effective tax rate for the nine-month period ended September 30,~~March 31, 2021 was above the ~~U.S.~~ statutory tax rate of 21% primarily due to losses recorded in Canada which have a higher tax rate, no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, ~~which has the impact of increasing the effective tax rate on an overall loss.~~

~~The effective tax rate for the nine-month period ended September 30, 2020 was below the statutory tax rate of 21% due to~~offset by exploration expenses in certain foreign jurisdictions in which no income tax benefit is ~~available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.~~currently available.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing ~~authorities, and currently the Company is under audit in several of these jurisdictions.~~authorities. These audits often take ~~multiple~~ 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 could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of ~~September 30, 2021,~~March 31, 2022, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; and Malaysia – ~~2014; and~~

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note K– Income Taxes~~ ~~(Contd.)~~

~~United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of 2019, the~~2014. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Note L – Financial Instruments and Risk Management

Murphy uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, 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.

Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss and amortized to the income statement over time. During the nine-month period ended September 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.

Commodity Price Risks

The Company has entered into crude oil swaps and collar contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives 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 mature monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity,

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Financial Instruments and Risk Management(Contd.)

collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

At ~~September 30, 2021,~~March 31, 2022, volumes per day associated with outstanding crude oil derivative contracts and the weighted average prices for these contracts are as follows:

September 30, 2021
2021 2022
NYMEX WTI swap contracts:
     Volume per day (Bbl): 45,000 20,000
     Price per Bbl: $ 42.77 $ 44.88
NYMEX WTI collar contracts:
     Volume per day (Bbl): — 16,000
     Price per Bbl:
          Ceiling: $ — $ 71.83
          Floor: — 60.38


	2022
NYMEX WTI swap contracts:
Volume per day (Bbl):	20,000
Price per Bbl:	$	44.88

NYMEX WTI collar contracts:
Volume per day (Bbl):	25,000
Price per Bbl:
Average Ceiling:	$	75.20
Average Floor:	$	63.24

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, 2021~~March 31, 2022 and ~~2020.~~2021.

At ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note L – Financial Instruments and Risk Management(Contd.)~~

September 30, 2021

December 31, 2020

(Thousands of dollars)

Asset (Liability) Derivatives

(Thousands of dollars)

Asset (Liability) Derivatives Fair Value

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Type of Derivative Contract

Balance Sheet Location

March 31, 2022

December 31, 2021

Commodity swaps

Accounts receivable

—

Accounts receivable

13,050

Commodity swaps

Accounts payable

(306,095)

(239,882)

Accounts payable

(312,448)

Accounts payable

(89,842)

Deferred credits and other liabilities

(41,645)

Deferred credits and other liabilities

(12,833)

Commodity collars

Accounts receivable

—

Accounts receivable

—

Commodity collars

Accounts receivable

—

4,280

Accounts payable

(15,929)

Accounts payable

—

Accounts payable

(162,123)

(19,533)

For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ 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)							Gain (Loss)
(Thousands of dollars)	(Thousands of dollars)	Statement of Operations Location		Three Months Ended September 30,					Nine months ended September 30,			(Thousands of dollars)		Statement of Operations Location		Three months ended March 31,
Type of Derivative Contract	Type of Derivative Contract		2021		2020			2021		2020	Type of Derivative Contract					2022	2021
Commodity swaps	Commodity swaps		(Loss) gain on derivative instruments		$	(43,235)		(5,290)		(483,865)		319,502	Commodity swaps		Loss on crude contracts			$	(156,359)	(214,385)
Commodity collars	Commodity collars	(Loss) gain on derivative instruments		(15,929)			—		(15,929)		—	Commodity collars		Loss on crude contracts			(164,418)	—

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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Financial Instruments and Risk Management(Contd.)

The carrying value of assets and liabilities recorded at fair value on a recurring basis at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, are presented in the following table.


		September 30, 2021					December 31, 2020					March 31, 2022					December 31, 2021
(Thousands of dollars)	(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
Assets:	Assets:										Assets:
Commodity swaps		$	—	—	—	—	—	13,050	—	13,050
Commodity collars											Commodity collars	$	—	—	—	—	—	4,280	—	4,280

		$	—	—	—	—	—	13,050	—	13,050		$	—	—	—	—	—	4,280	—	4,280

Liabilities:	Liabilities:										Liabilities:
Nonqualified employee savings plan											Nonqualified employee savings plan	$	17,038	—	—	17,038	16,962	—	—	16,962
Commodity collars	Commodity collars	$	—	15,929	—	15,929	—	—	—	—	Commodity collars	—		162,123	—	162,123	—	19,533	—	19,533
Nonqualified employee savings plan		17,180		—	—	17,180	14,988	—	—	14,988
Contingent consideration											Contingent consideration	—		—	239,108	239,108	—	—	196,151	196,151
Commodity swaps	Commodity swaps	—		354,093	—	354,093	—	102,675	—	102,675	Commodity swaps	—		306,095	—	306,095	—	239,882	—	239,882
Contingent consideration		—		—	238,115	238,115	—	—	133,004	133,004
		$	17,180	370,022	238,115	625,317	14,988	102,675	133,004	250,667		$	17,038	468,218	239,108	724,364	16,962	259,415	196,151	472,528

The fair value of commodity (WTI crude oil) ~~derivative contracts in 2021 and 2020 were~~swaps was based on active market quotes for WTI crude oil. The fair value of commodity (WTI crude oil) collars was determined using an option pricing model. The before tax income effect of changes in the fair value of crude oil derivative contracts is recorded in ~~Gain (loss)~~Loss on ~~derivative instruments~~crude contracts in the Consolidated Statements of Operations.

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.

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note L – Financial Instruments and Risk Management(Contd.)~~

The contingent consideration, related to 22018 and 2019 U.S. Gulf of Mexico acquisitions, ~~in 2019 and 2018,~~ is valued using a Monte Carlo simulation model. ~~The~~For the three months ended March 31, 2022 and 2021, the pre-tax income effect of changes in the fair value of the contingent consideration was an expense of $98.1 million and $14.9 million respectively and is recorded in Other operating expense ~~(benefit)~~ in the Consolidated Statements of Operations. In the three months ended March 31, 2022, the pre-tax income effect of changes in the fair value of the contingent consideration exclude cash payments of $55.2 million, which reduced the value of the contingent consideration liability. Contingent consideration is payable annually in years 2022 to 2026.

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, 2021~~March 31, 2022 and December 31, ~~2020.~~2021.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Accumulated Other Comprehensive Loss

The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, ~~2020~~2021 and ~~September 30, 2021~~March 31, 2022 and the changes during the ~~nine-month~~three-month period ended ~~September 30, 2021,~~March 31, 2022, 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		Deferred Loss on Interest Rate Derivative Hedges		Total	(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Total
Balance at December 31, 2020		$	(324,011)	(275,632)		(1,690)		(601,333)
Balance at December 31, 2021									Balance at December 31, 2021	$	(311,895)	(215,816)		(527,711)
Components of other comprehensive income (loss):	Components of other comprehensive income (loss):								Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	Before reclassifications to income and retained earnings	6,534		—		—		6,534	Before reclassifications to income and retained earnings	18,020		—		18,020
Reclassifications to income	Reclassifications to income	—		12,935	¹	1,690	²	14,625	Reclassifications to income	—		3,336	¹	3,336
Net other comprehensive income (loss)	Net other comprehensive income (loss)	6,534		12,935		1,690		21,159	Net other comprehensive income (loss)	18,020		3,336		21,356
Balance at September 30, 2021		$	(317,477)	(262,697)		—		(580,174)
Balance at March 31, 2022									Balance at March 31, 2022	$	(293,875)	(212,480)		(506,355)

1 Reclassifications before taxes of ~~$16,282~~$4,210 are included in the computation of net periodic benefit expense for the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022. See Note H for additional information. Related income taxes of ~~$3,347~~$874 are included in Income tax expense (benefit) for the ~~nine-month~~three-month period ended ~~September 30, 2021.~~

2 Reclassifications before taxes of $2,140 are included in Interest expense, net, for the nine-month period ended September 30, 2021. Related income taxes of $450 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2021. See Note L for additional information.March 31, 2022.

Note N – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

ENVIRONMENTAL, HEALTH AND SAFETY 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 emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and

safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.

Violation of 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

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note N– Environmental and Other Contingencies~~ ~~(Contd.)~~

could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable laws and regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. 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 recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings.

The Biden administration has indicated that it intends to increase regulatory oversight of the oil and gas industry, with a focus on climate change and greenhouse gas emissions (including methane emissions). The Biden administration has issued a number of executive orders that address climate change, including creation of climate-related task forces, directives to federal agencies

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

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. The Biden administration has also issued orders 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, on January 20, 2021, President Biden began the 30-day process of rejoining 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 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, 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 – 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 ~~crude oil contracts)~~commodity price derivatives), interest expense and unallocated overhead, is shown in the ~~tables~~table to reconcile the business segments to consolidated totals.

~~Table of Contents~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~


		Total Assets at September 30, 2021			Three Months Ended September 30, 2021				Three Months Ended September 30, 2020				Total Assets at March 31, 2022			Three Months Ended March 31, 2022				Three Months Ended March 31, 2021
(Millions of dollars)	(Millions of dollars)				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											Exploration and production ¹
United States	United States	$	6,586.3		565.2		168.1		330.8		(172.6)	United States	$	6,832.0		707.4		252.9		490.3		119.0
Canada	Canada	2,241.2			124.6		73.9		96.3		(8.6)	Canada	2,309.8			166.1		22.7		104.0		(124.3)
Other	Other	264.6			—		(5.2)		—		(11.7)	Other	242.1			—		(44.2)		—		(6.9)
Total exploration and production	Total exploration and production	9,092.1			689.8		236.8		427.1		(192.9)	Total exploration and production	9,383.9			873.5		231.4		594.3		(12.2)
Corporate	Corporate	1,237.8			(59.1)		(98.8)		(5.2)		(72.9)	Corporate	1,157.1			(320.5)		(296.3)		(214.3)		(254.8)
Continuing operations	Continuing operations	10,329.9			630.7		138.0		421.9		(265.8)	Continuing operations	10,541.0			553.0		(64.9)		380.0		(267.0)
Discontinued operations, net of tax	Discontinued operations, net of tax	1.0			—		(0.7)		—		(0.8)	Discontinued operations, net of tax	0.7			—		(0.6)		—		0.2
Total	Total	$	10,330.9		630.7		137.3		421.9		(266.6)	Total	$	10,541.7		553.0		(65.5)		380.0		(266.8)

					Nine Months Ended September 30, 2021				Nine Months Ended September 30, 2020
(Millions of dollars)				External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States					1,704.4		481.8		1,070.6		(1,011.7)
Canada					349.2		(37.7)		245.2		(35.0)
Other					—		(22.5)		1.8		(73.0)
Total exploration and production					2,053.6		421.6		1,317.6		(1,119.7)
Corporate					(493.3)		(577.6)		319.5		26.9
Continuing operations					1,560.3		(156.0)		1,637.1		(1,092.8)
Discontinued operations, net of tax					—		(0.6)		—		(6.9)
Total					1,560.3		(156.6)		1,637.1		(1,099.7)

1 Additional details about results of oil and natural gas operations are presented in the table on ~~pages 25 and 26.~~page 24.

2120

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

In ~~2021,~~ the ~~global distribution~~first quarter of 2022, crude oil and ~~administration of vaccinations in response~~natural gas benchmark prices increased when compared to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to an improving global economic outlook and subsequently increased demand for oil and gas. Emerging COVID-19 variants, such as the Delta variant, continue to create uncertaintysame period of 2021. Prices were higher in the ~~outlook, however~~first quarter 2022 principally due to market concerns over supply shortfalls stemming from lack of investment in ~~2021~~the exploration and production sector, ongoing demand ~~for~~recovery from COVID-19 and geopolitical uncertainty following the Russian invasion of Ukraine.

On input costs, and similarly to the overall inflationary pressure observed in the wider economy; the oil and gas ~~has remained resilient. The demand resilience has revealed an oil supply shortage,~~industry, and hence the Company, is ~~applying upward pressure to current~~observing higher costs for goods and ~~future oil~~services used in exploration and ~~gas prices.~~

~~The OPEC+ group of oil producing countries (OPEC+)~~production. Murphy continues to ~~target increasing~~manage input costs through its dedicated procurement department focused on managing supply by 0.4 million bpd a month, with aims to fully phase out prior cuts by September 2022, at the current rate of OPEC+ supply increases. In 2020 OPEC+ cut production by 10 million barrels per day (bpd) following the COVID-19 demand reduction. It has gradually reinstated supply so that the curtailments are approximately 5.8 million bpd at the end of September 2021. However, some members of the OPEC+ are falling short on supply increases.

~~Overall, the combination of OPEC+ supply constraints~~chain and the increase in demand driven by the global COVID-19 vaccine roll out has provided upward pressure to the oil price which directly impacts the Company’s product revenue from sales compared to one year ago.other costs.

For the three months ended ~~September 30, 2021,~~March 31, 2022, West Texas Intermediate (WTI) crude oil prices averaged approximately ~~$70.56~~$94.29 per barrel (compared to ~~$66.07~~$57.84 in the ~~second~~first quarter of 2021 and ~~$40.93~~$77.19 in the ~~third~~fourth quarter of ~~2020)~~2021). The closing price for WTI at the end of the ~~third~~first quarter of ~~2021~~2022 was approximately ~~$71.54~~$108.26 per barrel, reflecting a ~~modest~~74% increase from the ~~second~~first quarter 2021 closing price and ~~an 81%~~a 51% increase from the ~~third~~fourth quarter ~~2020~~of 2021 closing price. The average price in ~~October 2021~~April 2022 was ~~$81.22~~$101.64 per barrel. As of close on ~~November~~May 2, ~~2021,~~2022, the NYMEX WTI forward curve price for the remainder of ~~2021~~2022 and ~~2022~~2023 were ~~$83.91~~$99.44 and ~~$76.27~~$86.38 per barrel, respectively.

In the third quarter of 2021, the Company continued to delever by redeeming $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 for the principal amount plus cash costs of $2.6 million. Earlier in 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which included redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and closing costs of $8.1 million. The proceeds from issue are reported net of costs to issue on the Consolidated Balance Sheets.

In the third quarter of 2021, the Company acquired an additional 7.525% working interest at Terra Nova in Canada following a commercial agreement to sanction an asset life extension project. This transaction deferred an asset obligation at Terra Nova by approximately 10 years and decreased the obligation associated with the abandonment liability of the working interest before the acquisition by approximately $72 million.

For the three months ended ~~September 30, 2021,~~March 31, 2022, the Company produced ~~163~~150 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing ~~operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 14.5 thousand barrels of oil equivalent per day (including NCI).~~operations. The Company invested ~~$110.5~~$304.7 million in capital expenditures (on a value of work done basis) in the three months ended September 30, 2021. The Company reported net income from continuing operations of $138.0 million for the three months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of $28.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $44.1 million, an after-tax non-cash credit of $53.6March 31, 2022, (which included $22.3 million related to the deferral of ~~asset retirement obligations and after-tax losses on contingent consideration of $22.4 million.~~

~~For~~ the ~~nine months ended September 30, 2021, the Company produced 170 thousand barrels of oil equivalent per day (including noncontrolling interest)~~Cutthroat exploration well in Brazil from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI). The Company invested $568.7 million in capital expenditures (on a value of work done basis) in the nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay Floating Production System (FPS). The FPS capital expenditures were reimbursed by Arclight in the first quarter of 2021 (see below)2021). The Company reported net loss from continuing operations of ~~$156.0~~$64.9 million for the ~~nine~~three months ended ~~September 30, 2021.~~March 31, 2022. This amount includes income attributable to noncontrolling interest of ~~$85.5~~$47.9 million ~~after-tax impairment charges of $128.0 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations~~ and after-tax losses on unrealized mark to market revaluations on commodity price ~~swap and collar~~derivative positions and contingent consideration of ~~$180.5~~$148.9 million and ~~$83.0~~$77.2 million, respectively.

~~Table of Contents~~

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)~~

~~Summary (contd.)~~

For the three months ended ~~September 30, 2020,~~March 31, 2021, the Company produced ~~163~~165 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested ~~$122.7~~$251.1 million in capital expenditures (on a value of work done basis)~~, in~~ for the ~~third quarter of 2020,~~three months ended March 31, 2021, which included ~~$19.3~~$17.2 million to fund the development of the King’s Quay ~~FPS.~~floating production system (which was subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of ~~$265.8~~$267.0 million for the ~~third quarter of 2020.~~three months ended March 31, 2021. This amount included ~~loss~~income attributable to noncontrolling interest of ~~$23.1~~$20.6 million, after-tax impairment charges of ~~$145.9~~$128.0 million and after-tax losses on unrealized mark to market revaluations on commodity price ~~hedge~~derivative positions and contingent consideration of ~~$54.8~~$121.3 million and ~~$11.1 million, respectively.~~

For the nine months ended September 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $680.3 million in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2020, which included $80.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $1,092.8 million for the nine months ended September 30, 2020. This amount included loss attributable to noncontrolling interest of $122.9 million, after-tax impairment charges of $854.2 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $82.5 million and $23.3$11.8 million, respectively.

In the first quarter of 2021, the Company’s subsidiary "Murphy Exploration & Production Company - USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of project costs from inception to closing with proceeds of $267.7 million.

On April 12, 2022, subsequent to quarter end, the Company announced that it has achieved first oil from the Khaleesi, Mormont, Samurai field development project in the deepwater Gulf of Mexico, as production has begun flowing through the Murphy-operated King’s Quay FPS.

Table of Contents

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

Summary (contd.)

Results of Operations

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


		Income (Loss)							Income (Loss)
		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2021		2020	2021	2020	(Millions of dollars)		2022		2021
Exploration and production	Exploration and production	$	236.8	(192.9)	421.6	(1,119.7)	Exploration and production		$	231.4	(12.2)
Corporate and other	Corporate and other	(98.8)		(72.9)	(577.6)	26.9	Corporate and other		(296.3)		(254.8)
Income (loss) from continuing operations		138.0		(265.8)	(156.0)	(1,092.8)
Loss from continuing operations							Loss from continuing operations		(64.9)		(267.0)
Discontinued operations ¹	Discontinued operations ¹	(0.7)		(0.8)	(0.6)	(6.9)	Discontinued operations ¹		(0.6)		0.2
Net income (loss) including noncontrolling interest		$	137.3	(266.6)	(156.6)	(1,099.7)
Net loss including noncontrolling interest							Net loss including noncontrolling interest		$	(65.5)	(266.8)

1 The Company has presented its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations in its consolidated financial statements.

Exploration and Production

Results of E&P continuing operations are presented by geographic segment below.


		Income (Loss)							Income (Loss)
		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2021		2020	2021	2020	(Millions of dollars)		2022		2021
Exploration and production	Exploration and production						Exploration and production
United States	United States	$	168.1	(172.6)	481.8	(1,011.7)	United States		$	252.9	119.0
Canada	Canada	73.9		(8.6)	(37.7)	(35.0)	Canada		22.7		(124.3)
Other	Other	(5.2)		(11.7)	(22.5)	(73.0)	Other		(44.2)		(6.9)
Total	Total	$	236.8	(192.9)	421.6	(1,119.7)	Total		$	231.4	(12.2)

2322

Table of Contents

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

Results of Operations (contd.)

Other key performance metrics

The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Millions of dollars, except per barrel of oil equivalents sold)	(Millions of dollars, except per barrel of oil equivalents sold)	2021		2020	2021	2020	(Millions of dollars, except per barrel of oil equivalents sold)		2022		2021
Net income (loss) attributable to Murphy (GAAP)		$	108.5	(243.6)	(242.1)	(976.8)
Income tax expense (benefit)		36.8		(62.6)	(62.5)	(248.9)
Net loss attributable to Murphy (GAAP)							Net loss attributable to Murphy (GAAP)		$	(113.3)	(287.4)
Income tax benefit							Income tax benefit		(17.0)		(88.2)
Interest expense, net	Interest expense, net	46.9		45.2	178.4	124.9	Interest expense, net		37.3		88.1
Depreciation, depletion and amortization expense ¹	Depreciation, depletion and amortization expense ¹	182.8		219.7	588.4	725.1	Depreciation, depletion and amortization expense ¹		156.6		188.3
EBITDA attributable to Murphy (Non-GAAP)	EBITDA attributable to Murphy (Non-GAAP)	375.0		(41.3)	462.2	(375.7)	EBITDA attributable to Murphy (Non-GAAP)		63.6		(99.2)
Mark-to-market (gain) loss on derivative instruments		(55.9)		69.3	228.5	(104.5)
Mark-to-market loss on derivative instruments							Mark-to-market loss on derivative instruments		188.5		153.5
Mark-to-market loss on contingent consideration							Mark-to-market loss on contingent consideration		98.1		14.9
Accretion of asset retirement obligations ¹							Accretion of asset retirement obligations ¹		10.5		10.5
Discontinued operations loss (income)							Discontinued operations loss (income)		0.6		(0.2)
Impairment of assets ¹	Impairment of assets ¹	—		186.5	171.3	1,072.5	Impairment of assets ¹		—		171.3
Mark-to-market loss (gain) on contingent consideration		28.4		14.0	105.1	(29.5)
Asset retirement obligation (gains) losses		(71.8)		—	(71.8)	—
Accretion of asset retirement obligations ¹		10.8		10.8	30.8	31.2
Unutilized rig charges	Unutilized rig charges	3.2		5.2	8.5	13.2	Unutilized rig charges		—		2.8
Foreign exchange (gains) losses		(2.8)		0.8	(1.5)	(2.5)
Discontinued operations loss		0.7		0.8	0.6	6.9
Restructuring expenses		—		5.0	—	46.4
Inventory loss		—		—	—	4.8
Seal insurance proceeds		—		(1.7)	—	(1.7)
Foreign exchange (gain) loss							Foreign exchange (gain) loss		—		1.3

Adjusted EBITDA attributable to Murphy (Non-GAAP)	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	287.6	249.4	933.7	661.1	Adjusted EBITDA attributable to Murphy (Non-GAAP)		$	361.3	254.9

Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	14,219		14,166	43,536	46,478	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)		12,565		13,670

Adjusted EBITDA per barrel of oil equivalents sold	Adjusted EBITDA per barrel of oil equivalents sold	$	20.23	17.61	21.45	14.22	Adjusted EBITDA per barrel of oil equivalents sold		$	28.75	18.65

1 Depreciation, depletion, and amortization expense, impairment of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED ~~SEPTEMBER 30,~~MARCH 31, 2022 AND 2021 ~~AND 2020~~


(Millions of dollars)	(Millions of dollars)	United States 1		Canada	Other	Total	(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended September 30, 2021
Three Months Ended March 31, 2022							Three Months Ended March 31, 2022
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	565.2	124.6	—	689.8	Oil and gas sales and other operating revenues	$	707.4	129.3	—	836.7
Sales of purchased natural gas							Sales of purchased natural gas	—		36.8	—	36.8
Lease operating expenses	Lease operating expenses	96.7		33.4	0.1	130.2	Lease operating expenses	99.9		36.9	—	136.8
Severance and ad valorem taxes	Severance and ad valorem taxes	10.8		0.8	—	11.6	Severance and ad valorem taxes	14.2		0.4	—	14.6
Transportation, gathering and processing	Transportation, gathering and processing	28.4		16.2	—	44.6	Transportation, gathering and processing	29.2		17.7	—	46.9
Costs of purchased natural gas							Costs of purchased natural gas	—		33.7	—	33.7
Depreciation, depletion and amortization	Depreciation, depletion and amortization	147.0		39.7	0.1	186.8	Depreciation, depletion and amortization	126.5		34.2	0.1	160.8
Accretion of asset retirement obligations							Accretion of asset retirement obligations	9.4		2.5	—	11.9

Accretion of asset retirement obligations		9.3		2.9	—	12.2
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	17.3		—	—	17.3	Dry holes and previously suspended exploration costs	—		—	32.8	32.8
Geological and geophysical	Geological and geophysical	—		—	0.3	0.3	Geological and geophysical	2.6		—	0.2	2.8
Other exploration	Other exploration	1.3		0.1	0.5	1.9	Other exploration	1.5		0.1	6.1	7.7
		18.6		0.1	0.8	19.5		4.1		0.1	39.1	43.3
Undeveloped lease amortization	Undeveloped lease amortization	3.1		0.1	1.8	5.0	Undeveloped lease amortization	2.4		0.1	1.8	4.3
Total exploration expenses	Total exploration expenses	21.7		0.2	2.6	24.5	Total exploration expenses	6.5		0.2	40.9	47.6
Selling and general expenses	Selling and general expenses	4.2		4.0	1.2	9.4	Selling and general expenses	8.3		5.1	2.4	15.8
Other ²		39.1		(71.7)	2.0	(30.6)
Other							Other	102.8		5.1	0.4	108.3
Results of operations before taxes	Results of operations before taxes	208.0		99.1	(6.0)	301.1	Results of operations before taxes	310.6		30.3	(43.8)	297.1
Income tax provisions (benefits)	Income tax provisions (benefits)	39.9		25.2	(0.8)	64.3	Income tax provisions (benefits)	57.7		7.6	0.4	65.7
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	168.1	73.9	(5.2)	236.8	Results of operations (excluding Corporate segment)	$	252.9	22.7	(44.2)	231.4

Three Months Ended September 30, 2020
Three months ended March 31, 2021							Three months ended March 31, 2021
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	330.8	96.3	—	427.1	Oil and gas sales and other operating revenues	$	490.3	104.0	—	594.3

Lease operating expenses	Lease operating expenses	91.5		32.6	0.4	124.5	Lease operating expenses	116.1		30.8	0.3	147.2
Severance and ad valorem taxes	Severance and ad valorem taxes	6.4		0.3	—	6.7	Severance and ad valorem taxes	8.9		0.3	—	9.2
Transportation, gathering and processing	Transportation, gathering and processing	29.3		12.0	—	41.3	Transportation, gathering and processing	28.5		14.4	—	42.9

Depreciation, depletion and amortization	Depreciation, depletion and amortization	166.2		59.6	0.5	226.3	Depreciation, depletion and amortization	149.6		44.8	0.5	194.9
Accretion of asset retirement obligations	Accretion of asset retirement obligations	9.4		1.4	—	10.8	Accretion of asset retirement obligations	9.0		1.5	—	10.5
Impairment of assets	Impairment of assets	205.1		—	—	205.1	Impairment of assets	—		171.3	—	171.3
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	0.6		—	—	0.6	Dry holes and previously suspended exploration costs	0.7		—	—	0.7
Geological and geophysical	Geological and geophysical	0.1		—	(0.1)	—	Geological and geophysical	0.6		—	0.2	0.8
Other exploration	Other exploration	0.6		0.1	3.6	4.3	Other exploration	0.6		—	5.0	5.6
		1.3		0.1	3.5	4.9		1.9		—	5.2	7.1
Undeveloped lease amortization	Undeveloped lease amortization	4.9		0.1	2.3	7.3	Undeveloped lease amortization	2.3		0.1	2.2	4.6
Total exploration expenses	Total exploration expenses	6.2		0.2	5.8	12.2	Total exploration expenses	4.2		0.1	7.4	11.7
Selling and general expenses	Selling and general expenses	5.3		3.4	1.6	10.3	Selling and general expenses	5.5		4.1	1.4	11.0
Other	Other	22.5		(1.5)	2.5	23.5	Other	21.5		3.1	(3.5)	21.1
Results of operations before taxes	Results of operations before taxes	(211.1)		(11.7)	(10.8)	(233.6)	Results of operations before taxes	147.0		(166.4)	(6.1)	(25.5)
Income tax (benefits) provisions		(38.5)		(3.1)	0.9	(40.7)
Income tax provisions (benefits)							Income tax provisions (benefits)	28.0		(42.1)	0.8	(13.3)
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	(172.6)	(8.6)	(11.7)	(192.9)	Results of operations (excluding Corporate segment)	$	119.0	(124.3)	(6.9)	(12.2)

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

2 ~~For the three months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.~~

~~Table of Contents~~

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations (contd.)~~

~~OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020~~

(Millions of dollars)
United
States 1
Canada Other Total
Nine Months Ended September 30, 2021
Oil and gas sales and other operating revenues $ 1,704.4 349.2 — 2,053.6
Lease operating expenses 303.3 100.0 0.4 403.7
Severance and ad valorem taxes 30.6 1.6 — 32.2
Transportation, gathering and processing 90.5 46.7 — 137.2
Depreciation, depletion and amortization 476.6 128.0 1.1 605.7
Accretion of asset retirement obligations 27.5 7.4 — 34.9
Impairment of assets — 171.3 — 171.3
Exploration expenses
Dry holes and previously suspended exploration costs 17.9 — — 17.9
Geological and geophysical 2.7 — 1.3 4.0
Other exploration 4.2 0.2 9.6 14.0
24.8 0.2 10.9 35.9
Undeveloped lease amortization 7.9 0.2 5.8 13.9
Total exploration expenses 32.7 0.4 16.7 49.8
Selling and general expenses 15.0 12.0 4.7 31.7
Other ² 133.5 (67.7) (1.2) 64.6
Results of operations before taxes 594.7 (50.5) (21.7) 522.5
Income tax provisions (benefits) 112.9 (12.8) 0.8 100.9
Results of operations (excluding Corporate segment) $ 481.8 (37.7) (22.5) 421.6
Nine months ended September 30, 2020
Oil and gas sales and other operating revenues $ 1,070.6 245.2 1.8 1,317.6
Lease operating expenses 386.5 90.6 1.2 478.3
Severance and ad valorem taxes 21.6 1.0 — 22.6
Transportation, gathering and processing 95.4 31.4 — 126.8
Depreciation, depletion and amortization 589.5 161.3 1.5 752.3
Accretion of asset retirement obligations 27.1 4.1 — 31.2
Impairment of assets 1,152.5 — 39.7 1,192.2
Exploration expenses
Dry holes and previously suspended exploration costs 8.3 — — 8.3
Geological and geophysical 9.4 0.1 4.1 13.6
Other exploration 4.3 0.4 13.1 17.8
22.0 0.5 17.2 39.7
Undeveloped lease amortization 14.8 0.3 6.9 22.0
Total exploration expenses 36.8 0.8 24.1 61.7
Selling and general expenses 16.6 13.2 5.5 35.3
Other 1.0 (2.5) 1.4 (0.1)
Results of operations before taxes (1,256.4) (54.7) (71.6) (1,382.7)
Income tax provisions (benefits) (244.7) (19.7) 1.4 (263.0)
Results of operations (excluding Corporate segment) $ (1,011.7) (35.0) (73.0) (1,119.7)

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

2 ~~For the nine months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.~~

2624

Table of Contents

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

Results of Operations (contd.)

Exploration and Production

~~Third~~First quarter ~~2021~~2022 vs. ~~2020~~2021

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

United States E&P operations reported earnings of ~~$168.1~~$252.9 million in the ~~third~~first quarter of ~~2021~~2022 compared to ~~a loss~~earnings of ~~$172.6~~$119.0 million in the ~~third~~first quarter of ~~2020.~~2021. Results were ~~$340.7~~$133.9 million favorable in the ~~2021 quarter~~2022 period compared to the ~~2020~~2021 period, ~~primarily due to~~driven by higher revenues ($~~234.4~~217.1 million), lower ~~impairment charge~~DD&A ($~~205.1~~23.1 million) ~~and depreciation, depletion and amortization (DD&A: $19.2~~, lower lease operating expenses (LOE: $16.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in the third quarter of 2020. Lower impairment charges were due to impairment charges recognized in the prior period related to Gulf of Mexico Cascade & Chinook field and no such charges in current period. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher other operating expense is primarily due to unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher exploration expense is primarily due to dry hole costs related to Silverback in the current period.

Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter of 2020. Results were favorable $82.5 million compared to the 2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($28.3 million) and lower DD&A ($19.9 million), partially offset by higher tax expense ($28.3 million) and higher transportation, gathering and processing ($4.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Montney. Lower DD&A is due to lower production volumes at Kaybob Duvernay due to normal well decline. Higher transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020. The result was $6.5 million favorable in the 2021 period versus 2020 primarily due lower exploration expenses in Brazil and Mexico.

~~Nine months 2021 vs. 2020~~

~~All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.~~

United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020. Results were $1,493.5 million favorable in 2021 period compared to the 2020 period primarily due to no impairment charges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($633.8 million), lower DD&A ($112.9 million), lower lease operating expenses (LOE: $83.2 million), partially offset by higher income tax expense ($357.629.7 million) and higher other operating expense ($~~132.5~~81.3 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in ~~2021~~2022 compared to ~~2020. The production impact of Hurricane Ida in the third quarter of~~ 2021, is offset by ~~the impact of multiple storms that occurred in 2020.~~lower oil sales and production volumes driven primarily by a focused effort to reduce capital expenditures to prioritize corporate debt reduction. Lower DD&A is a result of ~~the prior year impairment charge reducing the depreciable asset base.~~lower production volumes and lower rates driven by positive reserve revisions. Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at ~~Cascade ($51.3 million) and Dalmatian ($20.5 million).~~St. Malo. Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense is primarily due to an unfavorable mark to market revaluation on contingent consideration ($~~105.1~~98.1 million; as a result of higher commodity prices) from prior GOM acquisitions.

Canadian E&P operations reported ~~a loss~~earnings of ~~$37.7~~$22.7 million in the first ~~nine months~~quarter of ~~2021~~2022 compared to a loss of ~~$35.0~~$124.3 million in the first ~~nine months~~quarter of ~~2020.~~2021. Results were ~~comparable~~$147.0 million favorable compared to the 2021 period. Prior year ~~over year. 2021~~ results ~~include~~included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment, and ~~a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of~~prior to the ~~deferral of an asset retirement obligation at Terra Nova following the sanction~~sanctioning of an asset life extension ~~project.~~project in the third quarter of 2021. The current year results also include higher revenue from production ($~~104.0~~25.3 million) and lower DD&A ($~~33.3~~10.6 million) offset by higher income tax expense ($49.7 million), lease operating expenses ($6.1 million) and transportation, gathering and processing expenses ($~~15.3 million) and lease operating expenses ($9.4~~3.3 million). Higher revenue is primarily attributable to higher oil prices at Hibernia and Kaybob Duvernay and higher natural gas prices and volumes at Tupper ~~Montney and higher oil prices at Hibernia and Kaybob Duvernay.~~Montney. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital

~~Table of Contents~~

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations (contd.)~~

expenditures throughout ~~2020.~~2020 and 2021. Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge. Higher lease ~~operating~~operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity. Higher capacity ~~which are~~is expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss of ~~$22.5~~$44.2 million in the first ~~nine months~~quarter of ~~2021~~2022 compared to a loss of ~~$73.0~~$6.9 million in the prior year. Results were ~~$50.5~~$37.3 million ~~favorable~~unfavorable compared to the ~~2020~~2021 period primarily due to ~~no repeat of an impairment charge of $39.7 million~~the Cutthroat-1 exploration well in block SEAL-M-428 in the ~~prior year.~~Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.

Corporate

~~Third~~First quarter ~~2021~~2022 vs. ~~2020~~

~~Nine months 2021 vs. 2020~~

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to ~~hedge/fix~~hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of ~~$577.6~~$296.3 million in the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~earnings~~a loss of ~~$26.9~~$254.8 million in the first ~~nine months~~quarter of ~~2020.~~2021. The ~~$604.5~~$41.5 million unfavorable variance is primarily due to higher realized and unrealized losses on derivative instruments in ~~2021~~2022 compared to ~~gains in 2020 (2021: $499.8~~2021 (2022: $320.8 million loss; ~~2020: $319.5~~2021: $214.4 million ~~gain), and higher interest expense ($54.1 million)~~loss), partially offset by lower interest expense ($56.0 million) and higher tax benefits ($~~177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2~~7.8 million). Realized and unrealized losses on derivative instruments are due to an increase in ~~market pricing in~~oil prices for current (realized) and future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of ~~September 30, 2021,~~March 31, 2022, the average forward NYMEX WTI price for the remainder of ~~2021 was $74.87 and for~~ 2022 was ~~$70.87~~$94.52 (versus swap contract fixed hedge ~~prices~~price of ~~$42.77 and $44.88, respectively)~~$44.88). Interest charges are ~~higher~~lower in ~~2021~~the first quarter of 2022 primarily due ~~an early~~the prior year redemption premium ($34.2 million) incurred by the Company upon the early retirement of the notes originally due June and December ~~2022.~~2022, lower overall debt and higher capitalized interest on GOM capital projects. Higher income tax benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

~~Production Volumes and Prices~~

~~Third quarter 2021 vs. 2020~~

Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020. U.S. Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms. The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020.

Average crude oil and condensate production from continuing operations was 88,245 barrels per day in the third quarter of 2021 compared to 95,391 barrels per day in the third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to Kaybob Duvernay well decline), lower volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a

Table of Contents

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

Results of Operations (contd.)

Production Volumes and Prices

First quarter 2022 vs. 2021

Total hydrocarbon production from Exploration and Production averaged 149,854 barrels of oil equivalent per day in the first quarter of 2022, which represented a 9% decrease from the 165,382 barrels per day produced in the first quarter of 2021. The decrease in production is principally due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction.

Average crude oil and condensate production was 83,560 barrels per day in the first quarter of 2022 compared to 97,475 barrels per day in the first quarter of 2021. The decrease of 13,915 barrels per day was principally due to lower Gulf of Mexico production (9,110 barrels per day) due to the focused effort to reduce capital expenditures and several planned downtime events including a facility upgrade which lowered current production at Neidermeyer and Marmalard as well as maintenance operations at Front Runner, Habanero and Chinook. Canada production is lower (3,176 barrels per day) due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia. Eagle Ford Shale production is lower (1,835 barrels per day) due to normal well decline and temporary operational issues impacting production in the first quarter of 2022. On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$68.88~~$95.17 per barrel in the ~~third~~first quarter ~~2021~~of 2022 compared to ~~$39.79~~$58.08 per barrel in the ~~2020~~2021 period, an increase of ~~73% quarter~~64% year over ~~quarter.~~year.

Total production of natural gas liquids (NGL) ~~from continuing operations~~ was ~~10,391~~9,342 barrels per day in the ~~third~~first quarter ~~2021~~of 2022 compared to ~~10,523~~9,845 barrels per day in the ~~2020~~2021 period. The average sales price for U.S. NGL was ~~$32.01~~$40.76 per barrel in ~~the 2021 quarter~~2022 compared to ~~$13.91~~$22.68 per barrel in ~~2020.~~2021. The average sales price for NGL in Canada was ~~$45.12~~$55.02 per barrel in ~~the 2021 quarter~~2022 compared to ~~$19.97~~$35.92 per barrel in ~~2020.~~2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas production volumes ~~from continuing operations~~ averaged ~~387.5~~341.7 million cubic feet per day (MMCFD) in the ~~third~~first quarter ~~2021~~of 2022 compared to ~~341.5~~348.4 MMCFD in ~~2020.~~2021. The ~~increase~~decrease of 466.7 MMCFD was aprimarily the result of ~~higher volumes in Canada (49 MMCFD), offset by~~ lower volumes in the Gulf of Mexico (7(16.6 MMCFD) ~~and in the~~partially offset by higher volumes at Eagle Ford Shale (4(5.3 MMCFD) and Canada (4.6 MMCFD). ~~Higher~~The lower natural gas ~~volumes in Canada are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Lower~~ volumes in the Gulf of Mexico are principally due to planned facility ~~shut-ins as a result of Hurricane Ida.~~

and maintenance downtime. Natural gas prices for the total Company averaged ~~$2.78~~$3.13 per thousand cubic feet (MCF) in the ~~2021~~first quarter of 2022, versus ~~$1.78~~$2.56 per MCF average in the same ~~quarter~~period of ~~2020.~~2021. Average realized natural gas prices in the U.S. and Canada in the quarter were ~~$3.99~~$5.00 and ~~$2.47 per MCF,~~$2.52, respectively.

~~Nine months 2021 vs. 2020~~

~~Total hydrocarbon production from all E&P continuing operations averaged 170,209 barrels of oil equivalent per day~~ Average realized gas prices in ~~the first nine months of 2021, which represented a 6% decrease from the 180,443 barrels per day produced in the first nine months of 2020. The decrease in production is principally due to~~Canada are lower ~~capital expenditures throughout 2020 to support generating positive free cashflow.~~

Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020. The decrease of 10,364 barrels per day was principally due to lower Gulf of Mexico production (5,472 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 and facility shut-ins as a result of Hurricane Ida in the third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged $64.19 per barrel in the first nine months of 2021 compared to $36.88 per barrel in the 2020 period, an increase of 74% year over year.certain fixed price sales volume contracts.

Total production of natural gas liquids (NGL) from continuing operations was 10,498 barrels per day in the first nine months of 2021 compared to 11,901 barrels per day in the 2020 period. The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in 2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas sales volumes from continuing operations averaged 368.4 million cubic feet per day (MMCFD) in the first nine months of 2021 compared to 359.2 MMCFD in 2020. The increase of 9.2 MMCFD was primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the first nine months of 2021, versus $1.68 per MCF average in the same period of 2020. Average natural gas prices in the U.S. and Canada in the quarter were $3.26 and $2.33, respectively.

Additional details about results of oil and natural gas operations are presented in the tables on ~~pages 25 and 26.~~page 24.

2926

Table of Contents

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

Results of Operations (contd.)

The following table ~~contains~~reports hydrocarbons produced during the three-month ~~and nine-month~~ periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021.


			Three Months Ended September 30,		Nine Months Ended September 30,				Three Months Ended March 31,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted		2021	2020	2021	2020	Barrels per day unless otherwise noted			2022	2021
Continuing operations

Net crude oil and condensate	Net crude oil and condensate						Net crude oil and condensate
United States	United States	Onshore	26,193	24,851	26,552	27,945	United States	Onshore		20,330	22,165
		Gulf of Mexico 1	53,011	56,517	61,905	67,377		Gulf of Mexico 1		55,253	64,363
Canada	Canada	Onshore	4,963	9,595	5,598	8,106	Canada	Onshore		4,380	6,288
		Offshore	3,779	4,428	4,016	5,136		Offshore		3,321	4,589
Other	Other		299	—	243	114	Other			276	70
Total net crude oil and condensate - continuing operations	Total net crude oil and condensate - continuing operations		88,245	95,391	98,314	108,678	Total net crude oil and condensate - continuing operations			83,560	97,475
Net natural gas liquids	Net natural gas liquids						Net natural gas liquids
United States	United States	Onshore	5,847	5,489	5,043	5,459	United States	Onshore		4,833	3,933
		Gulf of Mexico 1	3,459	3,521	4,296	5,131		Gulf of Mexico 1		3,526	4,679
Canada	Canada	Onshore	1,085	1,513	1,159	1,311	Canada	Onshore		983	1,233
Total net natural gas liquids - continuing operations	Total net natural gas liquids - continuing operations		10,391	10,523	10,498	11,901	Total net natural gas liquids - continuing operations			9,342	9,845
Net natural gas – thousands of cubic feet per day	Net natural gas – thousands of cubic feet per day						Net natural gas – thousands of cubic feet per day
United States	United States	Onshore	31,478	27,520	27,750	29,054	United States	Onshore		27,361	22,016
		Gulf of Mexico 1	46,339	53,046	63,557	67,850		Gulf of Mexico 1		56,058	72,658
Canada	Canada	Onshore	309,709	260,895	277,077	262,279	Canada	Onshore		258,291	253,697
Total net natural gas - continuing operations	Total net natural gas - continuing operations		387,526	341,461	368,384	359,183	Total net natural gas - continuing operations			341,710	348,371
Total net hydrocarbons - continuing operations including NCI 2,3	Total net hydrocarbons - continuing operations including NCI 2,3		163,224	162,824	170,209	180,443	Total net hydrocarbons - continuing operations including NCI 2,3			149,854	165,382
Noncontrolling interest	Noncontrolling interest						Noncontrolling interest
Net crude oil and condensate – barrels per day	Net crude oil and condensate – barrels per day		(7,546)	(9,298)	(8,834)	(10,674)	Net crude oil and condensate – barrels per day			(8,128)	(9,174)
Net natural gas liquids – barrels per day	Net natural gas liquids – barrels per day		(243)	(327)	(322)	(443)	Net natural gas liquids – barrels per day			(287)	(354)
Net natural gas – thousands of cubic feet per day 2	Net natural gas – thousands of cubic feet per day 2		(2,331)	(3,269)	(3,498)	(4,137)	Net natural gas – thousands of cubic feet per day 2			(2,590)	(4,159)
Total noncontrolling interest	Total noncontrolling interest		(8,178)	(10,170)	(9,739)	(11,807)	Total noncontrolling interest			(8,847)	(10,221)
Total net hydrocarbons - continuing operations excluding NCI 2,3	Total net hydrocarbons - continuing operations excluding NCI 2,3		155,046	152,654	160,470	168,636	Total net hydrocarbons - continuing operations excluding NCI 2,3			141,007	155,161

1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).

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

3 NCI – noncontrolling interest in MP GOM.

3027

Table of Contents

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

Results of Operations (contd.)

The following table ~~contains~~reports the weighted average sales prices excluding transportation cost deduction and sales of purchased natural gas for the three-month ~~and nine-month~~ periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.Comparative periods are conformed to current presentation.~~2021.


			Three Months Ended September 30,		Nine Months Ended September 30,				Three Months Ended March 31,
			2021	2020	2021	2020				2022		2021
Weighted average Exploration and Production sales prices	Weighted average Exploration and Production sales prices						Weighted average Exploration and Production sales prices
Continuing operations	Continuing operations						Continuing operations
Crude oil and condensate – dollars per barrel	Crude oil and condensate – dollars per barrel						Crude oil and condensate – dollars per barrel
United States	United States	Onshore	69.30	37.83	64.16	35.56	United States	Onshore		$	93.87	57.41
		Gulf of Mexico 1	68.93	40.82	64.44	38.08		Gulf of Mexico 1		95.02		58.78
Canada 2	Canada 2	Onshore	63.76	36.65	58.70	30.29	Canada 2	Onshore		93.09		52.84
		Offshore	72.64	43.81	68.93	37.85		Offshore		110.66		59.39
Other			—	—	—	63.51

Natural gas liquids – dollars per barrel	Natural gas liquids – dollars per barrel						Natural gas liquids – dollars per barrel
United States	United States	Onshore	30.37	13.39	24.29	10.78	United States	Onshore		38.32		21.25
		Gulf of Mexico 1	34.71	14.71	27.17	9.43		Gulf of Mexico 1		44.05		23.87
Canada 2	Canada 2	Onshore	45.12	19.97	37.05	16.95	Canada 2	Onshore		55.02		35.92
Natural gas – dollars per thousand cubic feet	Natural gas – dollars per thousand cubic feet						Natural gas – dollars per thousand cubic feet
United States	United States	Onshore	3.85	1.78	3.23	1.76	United States	Onshore		4.61		3.27
		Gulf of Mexico 1	4.09	2.01	3.28	1.91		Gulf of Mexico 1		5.19		3.39
Canada 2	Canada 2	Onshore	2.47	1.74	2.33	1.62	Canada 2	Onshore		2.52		2.26

1 Prices include the effect of noncontrolling interest share for MP GOM.

2 U.S. dollar equivalent.

Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was ~~$1,091.3~~$338.3 million for the first ~~nine~~three months of ~~2021~~2022 compared to ~~$578.0~~$237.8 million during the same period in ~~2020.~~2021. The increased cash from operating activities is primarily attributable to higher revenue from ~~sales to customers~~production ($~~727.3~~242.0 million), ~~lower~~offset by the timing of working capital settlements ($~~143.6 million), lower lease operating expense ($74.6 million),~~80.9 million; primarily higher revenue received in cash following the end of the quarter) and ~~lower general and administrative and cash restructuring expense~~higher realized losses on derivative instruments ($~~47.4 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $271.3 million; 2020: realized gain of $215.0~~71.4 million).

Cash Required by Investing Activities

Net cash required by investing activities was ~~$311.9~~$244.9 million for the first ~~nine~~three months of ~~2021~~2022 compared to ~~$723.7~~net cash provided by investing activities of $9.7 million during the same period in ~~2020. Property additions and dry hole costs, which includes amounts expensed, were $582.0 million and $723.7 million in the~~2021. The first ~~nine months~~quarter of 2021 ~~and 2020, respectively. These amounts include $17.7 million and $74.9 million used to fund the development of~~included sales proceeds for the King’s Quay FPS ~~in the first nine months~~ of ~~2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS~~$268.0 million, which was sold to ArcLight Capital Partners, LLC (ArcLight) ~~for proceeds~~. Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were $244.9 million and $240.5 million in the first three months of ~~$267.7 million, which reimbursed the Company for previously incurred~~2022 and 2021, respectively.

Total accrual basis capital ~~expenditures. Lower~~expenditures were as follows:


	Three Months Ended March 31,
(Millions of dollars)	2022		2021
Capital Expenditures
Exploration and production	$	299.4	247.3
Corporate	5.3		3.8
Total capital expenditures	$	304.7	251.1

A reconciliation of property additions and dry hole costs in ~~2021 are principally due~~the Consolidated Statements of Cash Flows to ~~lower~~total capital ~~spending at Eagle Ford Shale and lower spend on King’s Quay.~~expenditures for continuing operations follows.

3128

Table of Contents

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

Financial Condition (contd.)

~~Total accrual basis~~


	Three Months Ended March 31,
(Millions of dollars)	2022		2021
Property additions and dry hole costs per cash flow statements	$	244.9	240.5
Property additions King's Quay per cash flow statements	—		17.7

Geophysical and other exploration expenses	9.4		5.8
Capital expenditure accrual changes and other	50.4		(13.0)
Total capital expenditures	$	304.7	251.1

The increase in capital ~~expenditures were as follows:~~

Nine Months Ended
September 30,
(Millions of dollars) 2021 2020
Capital Expenditures
Exploration and production $ 556.0 671.0
Corporate 12.7 9.3
Total capital expenditures $ 568.7 680.3

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

Nine Months Ended
September 30,
(Millions of dollars) 2021 2020
Property additions and dry hole costs per cash flow statements $ 564.2 648.7
Property additions King's Quay per cash flow statements 17.7 74.9
Geophysical and other exploration expenses 13.3 26.8
Capital expenditure accrual changes and other (26.6) (70.2)
Total capital expenditures $ 568.7 680.3

~~Capital~~ expenditures in the exploration and production business in ~~2021~~2022 compared to ~~2020 have decreased as a result of~~2021 is primarily attributable to expenditures related to the Cutthroat-1 exploration well in Brazil, capital ~~expenditure reductions to support generating positive free cash flow.~~invested at the Khaleesi, Mormont, Samurai field development project and higher development drilling activities in Tupper Montney and Kaybob Duvernay assets.

Cash ~~Used in/ Provided~~Required by Financing Activities

Net cash required by financing activities was ~~$585.6~~$133.9 million for the first ~~nine~~three months of ~~2021~~2022 compared to ~~net cash provided by financing activities of $59.1~~$327.8 million during the same period in ~~2020.~~2021. In 2022, the cash used in financing activities was principally for payment of contingent consideration related prior Gulf of Mexico acquisitions ($55.2 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($39.9 million), and cash dividends to shareholders of $0.15 per share ($23.3 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.175 per share, or $0.70 per share on an annualized basis. This amount represents a 17% increase from the first quarter of 2022 and a 40% increase from fourth quarter 2021.

As of March 31, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.

In first three months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ~~and 2024~~ ($~~726.4 million)~~576.4 million), early redemption cost ~~(make whole payment)~~ of the notes due 2022 ($~~36.8~~34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($~~100.9~~36.0 million), and cash dividends to shareholders ($~~57.9~~19.3 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($~~541.9~~542.0 million).

~~As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.~~

In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($450.0 million), offset by repayments on the revolving credit facility ($250.0 million), cash dividends to shareholders ($76.8 million), and distributions to our noncontrolling interest ($43.7 million).

Working Capital

Working capital (total current assets less total current liabilities, – excluding assets and liabilities held for sale) ~~at September 30, 2021~~as of March 31, 2022 was a deficit of ~~$344.9~~$654.5 million, ~~$315.5~~ $355.7 million lower than December 31, ~~2020,~~2021, with the decrease ~~primarily~~primarily attributable to higher accounts payable ($~~208.3~~316.8 million), higher other accrued liabilities ($~~165.6~~80.5 million), a lower cash balance ($40.6 million) and higher operating lease liabilities ($~~53.5~~34.5 million), ~~partly~~partially offset by a higher ~~cash balance ($194.5 million) and lower~~ accounts receivable ($~~75.3~~113.7 million). Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments ~~(swaps~~(commodity price swaps and collars) maturing inover the ~~next 12 months.~~remainder of 2022. Higher other accrued liabilities are associated with higher contingent consideration obligations due to higher commodity prices (from ~~2018 and 2019~~prior Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the ~~Khaleesi-Mormont and~~Khaleesi, Mormont, Samurai ~~developments~~field development project which will utilize the King’s Quay FPS. ~~Lower~~Higher accounts receivable are principally due to higher crude oil pricing.

Capital Employed

At March 31, 2022, long-term debt of $2,466.1 million had increased by $0.7 million compared to December 31, 2021, primarily as a result of normal debt issuance cost amortization. The total of the ~~timing~~fixed-rate notes had a weighted average maturity of ~~cash received from our joint venture partners to fund joint operations.~~7.2 years and a weighted average coupon of 6.2%.

3229

Table of Contents

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

Financial Condition (contd.)

~~Capital Employed~~

At September 30, 2021, long-term debt of $2,613.7 million had decreased by $374.4 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.

A summary of capital employed at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 follows.


		September 30, 2021				December 31, 2020					March 31, 2022				December 31, 2021
(Millions of dollars)	(Millions of dollars)	Amount		%		Amount		%		(Millions of dollars)	Amount		%		Amount		%
Capital employed	Capital employed									Capital employed
Long-term debt	Long-term debt	$	2,613.7	39.8	%	$	2,988.1	41.5	%	Long-term debt	$	2,466.1	37.9	%	$	2,465.4	37.2	%
Murphy shareholders' equity	Murphy shareholders' equity	3,949.5		60.2	%	4,214.3		58.5	%	Murphy shareholders' equity	4,032.8		62.1	%	4,157.3		62.8	%
Total capital employed	Total capital employed	$	6,563.2	100.0	%	$	7,202.4	100.0	%	Total capital employed	$	6,499.0	100.0	%	$	6,622.7	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. ~~At September 30, 2021,~~As of March 31, 2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$119.4~~$144.3 million in ~~Canada and $6.2~~Canada. In addition, approximately $28.4 million of cash was held in ~~Brunei.~~Brazil. 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.

Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements

Outlook

As discussed in the Summary section on page ~~23,~~21, several factors continue to provide upward pressure to the average crude oil ~~prices continued to recover during~~price, which directly impacts the ~~second half of 2021 versus 2020 (Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93)~~Company’s product revenue from sales (Q1 2022: $94.29; Q1 2021: $57.84; Q4 2021: $77.19). As of close on ~~November~~May 2, ~~2021,~~2022, the NYMEX WTI forward curve price for the remainder of ~~2021~~2022 and ~~2022~~2023 were ~~$83.91~~$99.44 and ~~$76.27~~$86.38 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and ~~OPEC+ decisions)~~production sector investment and the Russia/Ukraine conflict) may have on future commodity ~~pricing.~~prices. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the ~~fourth~~second quarter, production is expected to average between ~~145.5~~156.0 and ~~153.5~~164.0 MBOEPD, excluding noncontrolling interest (NCI).

The Company’s capital expenditure spend for ~~2021~~2022 is expected to be between ~~$675.0~~$900.0 million and ~~$685.0~~$950.0 million. The increase from the original 2022 guidance of $840.0 million to $890.0 million is principally a result of inflationary pressures, scope changes and rig standby costs related to the Cutthroat-1 exploration well in Brazil. Capital expenditures 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~~plans to fund its remaining capital program in ~~2021~~2022 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) to repay outstanding debt.

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 revolving credit facility (see Note F). ~~The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the progress of the vaccination roll-outs globally.~~

As of ~~November~~May 2, ~~2021,~~2022, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

Commodity

Type

Volumes
(Bbl/d)

Price
(USD/Bbl)

Remaining Period

Commodity

Type

Volumes
(Bbl/d)

Price
(USD/Bbl)

Remaining Period

Area

Start Date

End Date

Area

Start Date

End Date

United States

WTI ¹

Fixed price derivative swap

45,000

$42.77

10/1/2021

12/31/2021

United States

WTI ¹

Fixed price derivative swap

20,000

$44.88

4/1/2022

12/31/2022

United States

WTI ¹

Fixed price derivative swap

20,000

$44.88

1/1/2022

12/31/2022

Volumes
(Bbl/d)

Average
Put
(USD/Bbl)

Average
Call
(USD/Bbl)

Remaining Period

Volumes
(Bbl/d)

Average
Put
(USD/Bbl)

Average
Call
(USD/Bbl)

Remaining Period

Area

Commodity

Type

Start Date

End Date

Area

Commodity

Type

Start Date

End Date

United States

WTI ¹

Derivative collars

23,000

$62.652

$74.774

1/1/2022

12/31/2022

United States

WTI ¹

Derivative collars

25,000

$63.24

$75.20

4/1/2022

12/31/2022

1 West Texas Intermediate

3330

Table of Contents

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

Volumes
(MMcf/d)

Price/Mcf

Remaining Period

Area

Commodity

Type

Start Date

End Date

Montney

Natural Gas

Fixed price forward sales

~~196~~

~~C$2.55~~

~~10/1/2021~~

~~12/31/2021~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales~~

~~186~~

~~C$2.36~~

~~1/1/2022~~

~~1/31/2022~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales~~

176

C$2.34

2/4/1/2022

4/30/2022

Montney

Natural Gas

Fixed price forward sales

205

C$2.34

5/1/2022

5/31/2022

Montney

Natural Gas

Fixed price forward sales

247

C$2.34

6/1/2022

10/31/2022

Montney

Natural Gas

Fixed price forward sales

266

C$2.36

11/1/2022

12/31/2022

Montney

Natural Gas

Fixed price forward sales

269

C$~~2.35~~2.36

1/1/2023

3/31/2023

Montney

Natural Gas

Fixed price forward sales

250

C$2.35

4/1/2023

12/31/2023

Montney

Natural Gas

Fixed price forward sales

162

C$2.39

1/1/2024

12/31/2024

Montney

Natural Gas

Fixed price forward sales

US$2.05

~~10/~~4/1/~~2021~~2022

12/31/2022

Montney

Natural Gas

Fixed price forward sales

US$1.98

1/1/2023

10/31/2024

Montney

Natural Gas

Fixed price forward sales

US$1.98

11/1/2024

12/31/2024

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in 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��~~“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 or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s ~~2020~~2021 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 3733 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

3431

Table of Contents

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 makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were commodity transactions in place at ~~September 30, 2021,~~March 31, 2022, covering certain future U.S. crude oil sales volumes ~~in 2021 and~~for the remainder of 2022. A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately ~~$113.6~~$109.5 million, while a 10% decrease would have decreased the recorded net payable by a similar amount.

There were no derivative foreign exchange contracts in place at ~~September 30, 2021.~~March 31, 2022.

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, 2021,~~March 31, 2022, 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.

3532

Table of Contents

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 its ~~2020~~2021 Form 10-K filed on February ~~26, 2021.~~25, 2022. The Company has not identified any additional risk factors not previously disclosed in its ~~2020~~2021 Form 10-K report.

ITEM 6. EXHIBITS

The Exhibit Index on page 3935 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

3633

Table of Contents

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/ CHRISTOPHER D. HULSE
						Christopher D. Hulse
						Vice President and Controller
						(Chief Accounting Officer and Duly Authorized Officer)

~~November~~May 4, ~~2021~~2022

(Date)

3734

Table of Contents

EXHIBIT INDEX

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


Exhibit No.

*31.1						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS						XBRL Instance Document
101. SCH						XBRL Taxonomy Extension Schema Document
101. CAL						XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF						XBRL Taxonomy Extension Definition Linkbase Document
101. LAB						XBRL Taxonomy Extension Labels Linkbase Document
101. PRE						XBRL Taxonomy Extension Presentation Linkbase

3835