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 June 30, ~~2021~~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 July 31, ~~2021~~2022 was ~~154,434,953~~155,452,838.

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 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			17
Note M – Accumulated Other Comprehensive Loss			19
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			20
~~Note P – Leases~~			21


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2322




Item 3. Quantitative and Qualitative Disclosures About Market Risk			3635
Item 4. Controls and Procedures			3635
Part II – Other Information			3736
Item 1. Legal Proceedings			3736
Item 1A. Risk Factors			3736
~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~			37
Item 6. Exhibits			3736
Signature			3837

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)	June 30, 2021		December 31, 2020	(Thousands of dollars)	June 30, 2022		December 31, 2021
ASSETS	ASSETS				ASSETS
Current assets	Current assets				Current assets
Cash and cash equivalents	Cash and cash equivalents	$	418,100	310,606	Cash and cash equivalents	$	432,019	521,184
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020		366,542		262,014
Accounts receivable, net					Accounts receivable, net	522,023		258,150
Inventories	Inventories	57,116		66,076	Inventories	63,886		54,198
Prepaid expenses	Prepaid expenses	36,027		33,860	Prepaid expenses	33,392		31,925
Assets held for sale	Assets held for sale	40,821		327,736	Assets held for sale	15,561		15,453
Total current assets	Total current assets	918,606		1,000,292	Total current assets	1,066,881		880,910
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,146,262 in 2021 and $11,455,305 in 2020		8,224,538		8,269,038
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,751,486 in 2022 and $12,457,851 in 2021					Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,751,486 in 2022 and $12,457,851 in 2021	8,295,655		8,127,852
Operating lease assets	Operating lease assets	973,801		927,658	Operating lease assets	855,975		881,389
Deferred income taxes	Deferred income taxes	457,600		395,253	Deferred income taxes	326,706		385,516
Deferred charges and other assets	Deferred charges and other assets	29,645		28,611	Deferred charges and other assets	26,994		29,273

Total assets	Total assets	$	10,604,190	10,620,852	Total assets	$	10,572,211	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	$	755	0	Current maturities of long-term debt, finance lease	$	670	654
Accounts payable	Accounts payable	744,067		407,097	Accounts payable	910,009		623,129
Income taxes payable	Income taxes payable	19,176		18,018	Income taxes payable	25,452		19,951
Other taxes payable	Other taxes payable	20,290		22,498	Other taxes payable	30,698		20,306
Operating lease liabilities	Operating lease liabilities	167,474		103,758	Operating lease liabilities	167,953		139,427
Other accrued liabilities	Other accrued liabilities	321,524		150,578	Other accrued liabilities	483,430		360,859
Liabilities associated with assets held for sale		0		14,372

Total current liabilities	Total current liabilities	1,273,286		716,321	Total current liabilities	1,618,212		1,164,326
Long-term debt, including finance lease obligation	Long-term debt, including finance lease obligation	2,762,851		2,988,067	Long-term debt, including finance lease obligation	2,267,934		2,465,414
Asset retirement obligations	Asset retirement obligations	817,502		816,308	Asset retirement obligations	863,892		839,776
Deferred credits and other liabilities	Deferred credits and other liabilities	738,407		680,580	Deferred credits and other liabilities	439,404		570,574
Non-current operating lease liabilities	Non-current operating lease liabilities	826,713		845,088	Non-current operating lease liabilities	706,016		761,162
Deferred income taxes	Deferred income taxes	143,603		180,341	Deferred income taxes	188,523		182,892

Total liabilities	Total liabilities	6,562,362		6,226,705	Total liabilities	6,083,981		5,984,144
Equity	Equity				Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, NaN issued		0		0
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
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 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	915,181		941,692	Capital in excess of par value	883,368		926,698
Retained earnings	Retained earnings	4,980,428		5,369,538	Retained earnings	5,405,400		5,218,670
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(553,519)		(601,333)	Accumulated other comprehensive loss	(554,727)		(527,711)
Treasury stock	Treasury stock	(1,656,591)		(1,690,661)	Treasury stock	(1,616,340)		(1,655,447)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	3,880,600		4,214,337	Murphy Shareholders' Equity	4,312,802		4,157,311
Noncontrolling interest	Noncontrolling interest	161,228		179,810	Noncontrolling interest	175,428		163,485
Total equity	Total equity	4,041,828		4,394,147	Total equity	4,488,230		4,320,796
Total liabilities and equity	Total liabilities and equity	$	10,604,190	10,620,852	Total liabilities and equity	$	10,572,211	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 June 30,			Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
(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	2022		2021
Revenues and other income	Revenues and other income							Revenues and other income
Revenue from sales to customers		$	758,829	285,745	$	1,351,356	886,303
(Loss) gain on crude contracts		(226,245)		(75,880)	(440,630)		324,792
Revenue from production								Revenue from production	$	1,146,299	758,829	$	1,980,827	1,351,356
Sales of purchased natural gas								Sales of purchased natural gas	49,939		—	86,785		—
Total revenue from sales to customers								Total revenue from sales to customers	1,196,238		758,829	2,067,612		1,351,356
Loss on crude contracts								Loss on crude contracts	(103,068)		(226,245)	(423,845)		(440,630)
Gain on sale of assets and other income	Gain on sale of assets and other income	17,059		1,677	18,902		4,175	Gain on sale of assets and other income	7,887		17,059	10,251		18,902
Total revenues and other income	Total revenues and other income	549,643		211,542	929,628		1,215,270	Total revenues and other income	1,101,057		549,643	1,654,018		929,628
Costs and expenses	Costs and expenses							Costs and expenses
Lease operating expenses	Lease operating expenses	126,413		144,644	273,577		353,792	Lease operating expenses	147,352		126,413	284,177		273,577
Severance and ad valorem taxes	Severance and ad valorem taxes	11,314		6,442	20,545		15,864	Severance and ad valorem taxes	17,565		11,314	32,200		20,545
Transportation, gathering and processing	Transportation, gathering and processing	49,696		41,090	92,608		85,457	Transportation, gathering and processing	49,948		49,696	96,871		92,608
Costs of purchased natural gas								Costs of purchased natural gas	47,971		—	81,636		—
Exploration expenses, including undeveloped lease amortization	Exploration expenses, including undeveloped lease amortization	13,543		29,468	25,323		49,594	Exploration expenses, including undeveloped lease amortization	15,151		13,543	62,717		25,323
Selling and general expenses	Selling and general expenses	29,113		39,100	58,616		75,872	Selling and general expenses	27,130		29,113	60,659		58,616
Restructuring expenses		0		41,397	0		41,397

Depreciation, depletion and amortization	Depreciation, depletion and amortization	227,288		231,446	425,566		537,548	Depreciation, depletion and amortization	195,856		227,288	359,980		425,566
Accretion of asset retirement obligations	Accretion of asset retirement obligations	12,164		10,469	22,656		20,435	Accretion of asset retirement obligations	11,563		12,164	23,439		22,656
Impairment of assets	Impairment of assets	0		19,616	171,296		987,146	Impairment of assets	—		—	—		171,296
Other expense (benefit)		70,328		22,007	91,407		(23,181)
Other operating expense								Other operating expense	36,913		70,328	142,855		91,407
Total costs and expenses	Total costs and expenses	539,859		585,679	1,181,594		2,143,924	Total costs and expenses	549,449		539,859	1,144,534		1,181,594
Operating income (loss) from continuing operations	Operating income (loss) from continuing operations	9,784		(374,137)	(251,966)		(928,654)	Operating income (loss) from continuing operations	551,608		9,784	509,484		(251,966)
Other income (loss)	Other income (loss)							Other income (loss)
Interest income and other (loss)		(4,525)		(5,171)	(9,866)		(4,930)
Other income (expense)								Other income (expense)	5,308		(4,525)	2,813		(9,866)
Interest expense, net	Interest expense, net	(43,374)		(38,598)	(131,474)		(79,695)	Interest expense, net	(41,385)		(43,374)	(78,662)		(131,474)
Total other loss		(47,899)		(43,769)	(141,340)		(84,625)
Loss from continuing operations before income taxes		(38,115)		(417,906)	(393,306)		(1,013,279)
Income tax benefit		(11,177)		(94,773)	(99,336)		(186,306)
Loss from continuing operations		(26,938)		(323,133)	(293,970)		(826,973)
Total other (loss)								Total other (loss)	(36,077)		(47,899)	(75,849)		(141,340)
Income (loss) from continuing operations before income taxes								Income (loss) from continuing operations before income taxes	515,531		(38,115)	433,635		(393,306)
Income tax (benefit) expense								Income tax (benefit) expense	105,084		(11,177)	88,123		(99,336)
Income (loss) from continuing operations								Income (loss) from continuing operations	410,447		(26,938)	345,512		(293,970)
(Loss) income from discontinued operations, net of income taxes	(Loss) income from discontinued operations, net of income taxes	(102)		(1,267)	106		(6,129)	(Loss) income from discontinued operations, net of income taxes	(943)		(102)	(1,494)		106
Net loss including noncontrolling interest		(27,040)		(324,400)	(293,864)		(833,102)
Less: Net income (loss) attributable to noncontrolling interest		36,042		(7,216)	56,656		(99,814)
NET LOSS ATTRIBUTABLE TO MURPHY		$	(63,082)	(317,184)	$	(350,520)	(733,288)
LOSS PER COMMON SHARE – BASIC
Net income (loss) including noncontrolling interest								Net income (loss) including noncontrolling interest	409,504		(27,040)	344,018		(293,864)
Less: Net income attributable to noncontrolling interest								Less: Net income attributable to noncontrolling interest	58,947		36,042	106,797		56,656
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY								NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	350,557	(63,082)	$	237,221	(350,520)
INCOME (LOSS) PER COMMON SHARE – BASIC								INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)	Continuing operations	$	2.27	(0.41)	$	1.54	(2.27)
Discontinued operations	Discontinued operations	0		(0.01)	0		(0.04)	Discontinued operations	(0.01)		—	(0.01)		—
Net loss		$	(0.41)	(2.06)	$	(2.27)	(4.78)
LOSS PER COMMON SHARE – DILUTED
Net income (loss)								Net income (loss)	$	2.26	(0.41)	$	1.53	(2.27)
INCOME (LOSS) PER COMMON SHARE – DILUTED								INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)	Continuing operations	$	2.24	(0.41)	$	1.51	(2.27)
Discontinued operations	Discontinued operations	0		(0.01)	0		(0.04)	Discontinued operations	(0.01)		—	(0.01)		—
Net loss		$	(0.41)	(2.06)	$	(2.27)	(4.78)
Net income (loss)								Net income (loss)	$	2.23	(0.41)	$	1.50	(2.27)
Cash dividends per Common share	Cash dividends per Common share	0.125		0.125	0.250		0.375	Cash dividends per Common share	$	0.175	0.125	0.325		0.250

Average Common shares outstanding (thousands)	Average Common shares outstanding (thousands)							Average Common shares outstanding (thousands)
Basic	Basic	154,395		153,581	154,153		153,429	Basic	155,389		154,395	155,121		154,153
Diluted	Diluted	154,395		153,581	154,153		153,429	Diluted	157,455		154,395	157,852		154,153

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 June 30,			Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021		2020	(Thousands of dollars)	2022		2021	2022		2021
Net (loss) including noncontrolling interest		$	(27,040)	(324,400)	$	(293,864)	(833,102)
Net income (loss) including noncontrolling interest								Net income (loss) including noncontrolling interest	$	409,504	(27,040)	$	344,018	(293,864)
Other comprehensive (loss) income, net of tax	Other comprehensive (loss) income, net of tax							Other comprehensive (loss) income, net of tax
Net (loss) gain from foreign currency translation	Net (loss) gain from foreign currency translation	17,945		50,568	37,842		(67,843)	Net (loss) gain from foreign currency translation	(51,545)		17,945	(33,525)		37,842
Retirement and postretirement benefit plans	Retirement and postretirement benefit plans	4,146		(39,234)	8,282		(48,945)	Retirement and postretirement benefit plans	3,173		4,146	6,509		8,282
Deferred loss on interest rate hedges reclassified to interest expense	Deferred loss on interest rate hedges reclassified to interest expense	0		309	1,690		608	Deferred loss on interest rate hedges reclassified to interest expense	—		—	—		1,690

Other comprehensive (loss) income	Other comprehensive (loss) income	22,091		11,643	47,814		(116,180)	Other comprehensive (loss) income	(48,372)		22,091	(27,016)		47,814
COMPREHENSIVE (LOSS)		$	(4,949)	(312,757)	$	(246,050)	(949,282)
Comprehensive income (loss) including noncontrolling interest								Comprehensive income (loss) including noncontrolling interest	$	361,132	(4,949)	317,002		(246,050)
Less: Comprehensive income attributable to noncontrolling interest								Less: Comprehensive income attributable to noncontrolling interest	58,947		36,042	106,797		56,656
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY								COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	302,185	(40,991)	$	210,205	(302,706)

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


		Six Months Ended June 30,				Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	(Thousands of dollars)	2022		2021
Operating Activities	Operating Activities				Operating Activities
Net (loss) including noncontrolling interest		$	(293,864)	(833,102)
Adjustments to reconcile net loss to net cash provided (required) by continuing operations activities
Net income (loss) including noncontrolling interest					Net income (loss) including noncontrolling interest	$	344,018	(293,864)
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities					Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities
Loss (income) from discontinued operations	Loss (income) from discontinued operations	(106)		6,129	Loss (income) from discontinued operations	1,494		(106)
Depreciation, depletion and amortization	Depreciation, depletion and amortization	425,566		537,548	Depreciation, depletion and amortization	359,980		425,566
Previously suspended exploration costs		633		7,677
Unsuccessful exploration well costs and previously suspended exploration costs					Unsuccessful exploration well costs and previously suspended exploration costs	34,102		633
Amortization of undeveloped leases	Amortization of undeveloped leases	8,882		14,770	Amortization of undeveloped leases	7,980		8,882
Accretion of asset retirement obligations	Accretion of asset retirement obligations	22,656		20,435	Accretion of asset retirement obligations	23,439		22,656
Deferred income tax (benefit) expense					Deferred income tax (benefit) expense	66,691		(101,195)
Mark to market loss on contingent consideration					Mark to market loss on contingent consideration	129,818		76,677
Mark to market loss on crude contracts					Mark to market loss on crude contracts	100,343		284,360
Long-term non-cash compensation					Long-term non-cash compensation	40,467		25,318
Impairment of assets	Impairment of assets	171,296		987,146	Impairment of assets	—		171,296
Noncash restructuring expense		0		17,565
Deferred income tax benefit		(101,195)		(167,902)

Mark to market loss (gain) on contingent consideration		76,677		(43,529)
Mark to market loss (gain) on crude contracts		284,360		(173,848)
Long-term non-cash compensation		25,318		22,760
(Gain) from sale of assets					(Gain) from sale of assets	(35)		—
Net (increase) decrease in noncash working capital	Net (increase) decrease in noncash working capital	26,565		1,335	Net (increase) decrease in noncash working capital	(121,598)		26,565
Other operating activities, net	Other operating activities, net	39,494		(27,605)	Other operating activities, net	(27,458)		39,494
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	686,282		369,379	Net cash provided by continuing operations activities	959,241		686,282
Investing Activities	Investing Activities				Investing Activities
Property additions and dry hole costs		(445,314)		(537,601)
Property additions and dry hole costs 1					Property additions and dry hole costs 1	(552,825)		(422,841)
Acquisition of oil and gas properties 1					Acquisition of oil and gas properties 1	(46,491)		(22,473)
Property additions for King's Quay FPS	Property additions for King's Quay FPS	(17,734)		(51,635)	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	269,363		0	Proceeds from sales of property, plant and equipment	47		269,363
Net cash (required) by investing activities	Net cash (required) by investing activities	(193,685)		(589,236)	Net cash (required) by investing activities	(599,269)		(193,685)
Financing Activities	Financing Activities				Financing Activities
Borrowings on revolving credit facility	Borrowings on revolving credit facility	165,000		370,000	Borrowings on revolving credit facility	100,000		165,000
Repayment of revolving credit facility	Repayment of revolving credit facility	(365,000)		(200,000)	Repayment of revolving credit facility	(100,000)		(365,000)
Retirement of debt	Retirement of debt	(576,358)		(12,225)	Retirement of debt	(200,000)		(576,358)
Debt issuance, net of cost	Debt issuance, net of cost	541,974		(613)	Debt issuance, net of cost	—		541,974
Early redemption of debt cost	Early redemption of debt cost	(34,177)		0	Early redemption of debt cost	(3,438)		(34,177)
Distributions to noncontrolling interest	Distributions to noncontrolling interest	(75,238)		(32,400)	Distributions to noncontrolling interest	(94,854)		(75,238)
Contingent consideration payment					Contingent consideration payment	(81,742)		—
Cash dividends paid	Cash dividends paid	(38,590)		(57,590)	Cash dividends paid	(50,491)		(38,590)
Withholding tax on stock-based incentive awards	Withholding tax on stock-based incentive awards	(3,895)		(7,247)	Withholding tax on stock-based incentive awards	(16,697)		(3,895)
Proceeds from term loan and other loans		0		371
Capital lease obligation payments	Capital lease obligation payments	(371)		(336)	Capital lease obligation payments	(320)		(371)

Net cash (required) provided by financing activities		(386,655)		59,960
Cash Flows from Discontinued Operations 1
Operating activities		0		(1,202)
Investing activities		0		4,494
Financing activities		0		0
Net cash provided by discontinued operations		0		3,292

Net cash (required) by financing activities					Net cash (required) by financing activities	(447,542)		(386,655)

Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	1,552		(1,358)	Effect of exchange rate changes on cash and cash equivalents	(1,595)		1,552
Net increase (decrease) in cash and cash equivalents		107,494		(161,255)
Net (decrease) increase in cash and cash equivalents					Net (decrease) increase in cash and cash equivalents	(89,165)		107,494
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	$	418,100	145,505	Cash and cash equivalents at end of period	$	432,019	418,100

1 ~~Net cash provided by discontinued operations is not part of~~Certain prior-period amounts have been reclassified to conform to the ~~cash flow reconciliation.~~ current period presentation.

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)


		Three Months Ended June 30,			Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021		2020	(Thousands of dollars)	2022		2021	2022		2021
Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued		$	0	0	$	0	0
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2021 and 195,100,628 shares at June 30, 2020
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 June 30, 2022 and 195,100,628 shares at June 30, 2021								Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2022 and 195,100,628 shares at June 30, 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	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	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	914,303		924,930	941,692		949,445	Balance at beginning of period	880,537		914,303	926,698		941,692
Exercise of stock options, including income tax benefits	Exercise of stock options, including income tax benefits	(587)		—	(626)		(156)	Exercise of stock options, including income tax benefits	(3,415)		(587)	(10,635)		(626)
Restricted stock transactions and other	Restricted stock transactions and other	(5,347)		(636)	(38,347)		(33,240)	Restricted stock transactions and other	—		(5,347)	(45,169)		(38,347)
Share-based compensation	Share-based compensation	6,812		7,135	12,462		15,380	Share-based compensation	6,246		6,812	12,474		12,462

Balance at end of period	Balance at end of period	915,181		931,429	915,181		931,429	Balance at end of period	883,368		915,181	883,368		915,181
Retained Earnings	Retained Earnings							Retained Earnings
Balance at beginning of period	Balance at beginning of period	5,062,813		6,159,808	5,369,538		6,614,304	Balance at beginning of period	5,082,034		5,062,813	5,218,670		5,369,538
Net (loss) attributable to Murphy		(63,082)		(317,184)	(350,520)		(733,288)
Net income (loss) attributable to Murphy								Net income (loss) attributable to Murphy	350,557		(63,082)	237,221		(350,520)

Cash dividends		(19,303)		(19,198)	(38,590)		(57,590)
Cash dividends paid								Cash dividends paid	(27,191)		(19,303)	(50,491)		(38,590)
Balance at end of period	Balance at end of period	4,980,428		5,823,426	4,980,428		5,823,426	Balance at end of period	5,405,400		4,980,428	5,405,400		4,980,428
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss							Accumulated Other Comprehensive Loss
Balance at beginning of period	Balance at beginning of period	(575,610)		(701,984)	(601,333)		(574,161)	Balance at beginning of period	(506,355)		(575,610)	(527,711)		(601,333)
Foreign currency translation gain (loss), net of income taxes		17,945		50,568	37,842		(67,843)
Foreign currency translation (loss) gain, net of income taxes								Foreign currency translation (loss) gain, net of income taxes	(51,545)		17,945	(33,525)		37,842
Retirement and postretirement benefit plans, net of income taxes	Retirement and postretirement benefit plans, net of income taxes	4,146		(39,234)	8,282		(48,945)	Retirement and postretirement benefit plans, net of income taxes	3,173		4,146	6,509		8,282
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	—		309	1,690		608	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	(553,519)		(690,341)	(553,519)		(690,341)	Balance at end of period	(554,727)		(553,519)	(554,727)		(553,519)
Treasury Stock	Treasury Stock							Treasury Stock
Balance at beginning of period	Balance at beginning of period	(1,661,416)		(1,691,706)	(1,690,661)		(1,717,217)	Balance at beginning of period	(1,618,478)		(1,661,416)	(1,655,447)		(1,690,661)

Awarded restricted stock, net of forfeitures	Awarded restricted stock, net of forfeitures	4,339		636	33,545		26,147	Awarded restricted stock, net of forfeitures	—		4,339	32,297		33,545
Exercise of stock options	Exercise of stock options	486		—	525		—	Exercise of stock options	2,138		486	6,810		525
Balance at end of period – 40,665,675 shares of Common Stock in 2021 and 41,512,066 shares of Common Stock in 2020, at cost		(1,656,591)		(1,691,070)	(1,656,591)		(1,691,070)
Balance at end of period – 39,677,584 shares of Common Stock in 2022 and 40,665,675 shares of Common Stock in 2021, at cost								Balance at end of period – 39,677,584 shares of Common Stock in 2022 and 40,665,675 shares of Common Stock in 2021, at cost	(1,616,340)		(1,656,591)	(1,616,340)		(1,656,591)
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	3,880,600		4,568,545	3,880,600		4,568,545	Murphy Shareholders’ Equity	4,312,802		3,880,600	4,312,802		3,880,600
Noncontrolling Interest	Noncontrolling Interest							Noncontrolling Interest
Balance at beginning of period	Balance at beginning of period	164,418		212,154	179,810		337,151	Balance at beginning of period	171,451		164,418	163,485		179,810

Net income (loss) attributable to noncontrolling interest		36,042		(7,216)	56,656		(99,814)
Net income attributable to noncontrolling interest								Net income attributable to noncontrolling interest	58,947		36,042	106,797		56,656
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(39,232)		(1)	(75,238)		(32,400)	Distributions to noncontrolling interest owners	(54,970)		(39,232)	(94,854)		(75,238)
Balance at end of period	Balance at end of period	161,228		204,937	161,228		204,937	Balance at end of period	175,428		161,228	175,428		161,228
Total Equity	Total Equity	$	4,041,828	4,773,482	$	4,041,828	4,773,482	Total Equity	$	4,488,230	4,041,828	$	4,488,230	4,041,828

See Notes to Consolidated Financial Statements, page 7.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries ~~(Murphy/the 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 June 30, ~~2021,~~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 Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, 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 six-month periods ended June 30, ~~2021~~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.

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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.

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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 six-month periods~~period ended June 30, 2022, and 2021, the Company recognized ~~$758.8~~$1,196 million and ~~$1,351.4~~$758.8 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 six-month periods ended June 30, 2020, the Company recognized $285.7 million and $886.3 million, respectively,~~ from ~~contracts with customers for the~~ sales of oil, natural gas liquids and natural gas.

Three Months Ended
June 30, Six Months Ended
June 30,
(Thousands of dollars) 2021 2020 2021 2020
Net crude oil and condensate revenue
United States Onshore $ 183,267 54,550 297,757 185,786
                      Offshore 411,076 150,253 739,417 497,225
Canada     Onshore 30,695 11,527 60,598 34,910
Offshore 31,772 11,077 49,834 35,691
Other 0 (58) 0 1,806
Total crude oil and condensate revenue 656,810 227,349 1,147,606 755,418
Net natural gas liquids revenue
United States Onshore 9,596 3,876 17,124 9,379
Offshore 10,766 3,464 20,820 8,490
Canada Onshore 3,240 1,276 7,227 3,310
Total natural gas liquids revenue 23,602 8,616 45,171 21,179
Net natural gas revenue
United States Onshore 6,872 4,090 13,315 9,648
Offshore 17,273 10,665 39,411 25,660
Canada    Onshore 54,272 35,025 105,853 74,398
Total natural gas revenue 78,417 49,780 158,579 109,706
Total revenue from contracts with customers 758,829 285,745 1,351,356 886,303
(Loss) gain on crude contracts (226,245) (75,880) (440,630) 324,792
Gain on sale of assets and other income 17,059 1,677 18,902 4,175
Total revenue and other income $ 549,643 211,542 929,628 1,215,270
For the six-month period ended June 30, 2022, and 2021, the Company recognized $2,067.6 million and $1,351.4 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.


		Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)		2022		2021	2022		2021
Net crude oil and condensate revenue
United States	Onshore	$	264,841	183,267	$	436,537	297,757
	Offshore	612,526		411,076	1,078,147		739,417
Canada	Onshore	40,417		30,695	77,114		60,598
	Offshore	38,354		31,772	67,186		49,834
Other		13,636		—	13,636		—
Total crude oil and condensate revenue		969,774		656,810	1,672,620		1,147,606

Net natural gas liquids revenue
United States	Onshore	18,062		9,596	34,747		17,124
	Offshore	18,093		10,766	32,072		20,820
Canada	Onshore	5,001		3,240	9,868		7,227
Total natural gas liquids revenue		41,156		23,602	76,687		45,171

Net natural gas revenue
United States	Onshore	19,034		6,872	30,403		13,315
	Offshore	43,567		17,273	69,768		39,411
Canada	Onshore	72,768		54,272	131,349		105,853
Total natural gas revenue		135,369		78,417	231,520		158,579

Revenue from production		1,146,299		758,829	1,980,827		1,351,356



Sales of purchased natural gas
United States	Offshore	181		—	181		—
Canada	Onshore	49,758		—	86,604		—
Total sales of purchased natural gas		49,939		—	86,785		—

Total revenue from sales to customers		1,196,238		758,829	2,067,612		1,351,356

Loss on crude contracts		(103,068)		(226,245)	(423,845)		(440,630)
Gain on sale of assets and other income		7,887		17,059	10,251		18,902
Total revenues and other income		$	1,101,057	549,643	$	1,654,018	929,628

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 June 30, ~~2021,~~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 ~~$206.6~~$292.4 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 atof June 30, ~~2021.~~2022.

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 June 30, ~~2021,~~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 June 30, ~~2021~~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

Q1Q2 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 ~~various~~ 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 June 30, 2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $197.5 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2021 and 2020.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

(Thousands of dollars) 2021 2020
Beginning balance at January 1 $ 181,616 217,326
Additions pending the determination of proved reserves 15,921 2,328
Capitalized exploratory well costs charged to expense 0 (39,519)
Balance at June 30 $ 197,537 180,135
As of June 30, 2022, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2022 and 2021.


(Thousands of dollars)	2022		2021
Beginning balance at January 1	$	179,481	181,616
Additions pending the determination of proved reserves	9,412		15,921

Capitalized exploratory well costs charged to expense	(10,472)		—
Balance at June 30	$	178,421	197,537

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.


		June 30,								June 30,
		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	$	13,881	3	3	24,429	3	3	Zero to one year	$	4,268	2	2	13,881	3	3
One to two years	One to two years	23,811		3	3	30,691	2	2	One to two years	2,813		2	2	23,811	3	3
Two to three years	Two to three years	30,562		2	2	0	0	0	Two to three years	26,848		3	2	30,562	2	2
Three years or more	Three years or more	129,283		6	0	125,015	6	0	Three years or more	144,492		8	2	129,283	6	—
		$	197,537	14	8	180,135	11	5		$	178,421	15	8	197,537	14	8

Of the ~~$183.6~~$174.2 million of exploratory well costs capitalized more than one year at June 30, ~~2021, $91.5~~2022, $94.7 million is in Vietnam, ~~$46.2~~$48.5 million is in the U.S., ~~$25.7~~$15.5 million is in ~~Brunei, $15.4~~Mexico, $10.6 million is in ~~Mexico,~~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 six months 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.~~

~~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~~plans at end of the ~~Company’s U.S. Offshore~~first quarter 2021. Later in 2021, the Company sanctioned an asset life extension project and ~~Other Foreign properties. The Company recorded pretax noncash impairment charges~~acquired an additional 7.525% working interest at Terra Nova following a commercial agreement to extend the life of ~~$987.1 million to reduce~~ the ~~carrying values to their estimated fair values at select properties.~~field.

~~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~~first six months ~~ended June 30, 2021 and 2020.~~

Six Months Ended
June 30,
(Thousands of dollars) 2021 2020
U.S. $ 0 947,437
Canada 171,296 0
Other Foreign 0 39,709
$ 171,296 987,146

~~Divestments~~

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.

Acquisitions

In June 2022, the Company acquired an additional working interest of 11.0% in the Kodiak field for a purchase price of $46.5 million, net of post-closing adjustments.

In the second quarter of 2021, the Company acquired an additional 3.5% working interest in the Lucius field for a purchase price of $22.5 million, net of post-closing adjustments.

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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 six-month periods ended June 30, ~~2021~~2022 and ~~2020~~2021 were as follows:


		Three Months Ended June 30,			Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2021		2020	2021		2020	(Thousands of dollars)	2022		2021	2022		2021
Revenues	Revenues	$	246	1	$	658	4,074	Revenues	$	—	246	$	10	658
Costs and expenses	Costs and expenses							Costs and expenses

Other costs and expenses (benefits)	Other costs and expenses (benefits)	348		1,268	552		10,203	Other costs and expenses (benefits)	943		348	1,504		552
(Loss) income before taxes	(Loss) income before taxes	(102)		(1,267)	106		(6,129)	(Loss) income before taxes	(943)		(102)	(1,494)		106
Income tax expense	Income tax expense	0		0	0		0	Income tax expense	—		—	—		—
(Loss) income from discontinued operations	(Loss) income from discontinued operations	$	(102)	(1,267)	$	106	(6,129)	(Loss) income from discontinued operations	$	(943)	(102)	$	(1,494)	106

As of June 30, 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 the 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) June 30,
2021 December 31,
2020
Current assets
Cash $ 0 10,185
Inventories 0 406
Property, plant, and equipment, net 40,820 307,704
Deferred income taxes and other assets — 9,441
Total current assets associated with assets held for sale $ 40,820 327,736
Current liabilities
Accounts payable $ 0 5,306
Other accrued liabilities 0 45
Current maturities of long-term debt (finance lease) 0 737
Taxes payable 0 1,510
Long-term debt (finance lease) 0 6,513
Asset retirement obligation 0 261
Total current liabilities associated with assets held for sale $ 0 14,372


(Thousands of dollars)	June 30, 2022		December 31, 2021
Current assets




Property, plant, and equipment, net	15,561		15,453


Total current assets associated with assets held for sale	$	15,561	15,453

Note F – Financing Arrangements and Debt

As of June 30, ~~2021,~~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 June 30, ~~2021,~~2022, the Company had 0no outstanding borrowings under the RCF and ~~$31.0~~$27.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, ~~2021,~~2022, the interest rate in effect on borrowings under the facility was ~~1.78%~~3.46%. At June 30, 2022 and 2021, the Company was in compliance with all covenants related to the RCF.

On June 2, 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $4.3 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months and six months ended June 30, 2022. The cash costs of $3.4 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the six months ended June 30, 2022.

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 ~~$8.0~~$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)~~

~~Table of Contents~~

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

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

(2022; collectively 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 three months and six months ended June 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the six months ended June 30, 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 ~~2021.~~15, 2024.

~~Subsequent to quarter end,~~On July 20, 2022, the Company issued a notice of ~~partial~~ redemption with respect to ~~$150.0~~all of its outstanding, $42.4 million aggregate principal amount, ~~of its~~ 6.875% senior notes due ~~2024 (2024 Notes).~~ 2024.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 August ~~16, 2021.~~19, 2022.

On August 1, 2022, the Company announced the commencement of cash tender offers (the “Tender Offers”) to purchase up to $200.0 million in aggregate purchase price of its outstanding 5.750% senior notes due 2025, 6.375% senior notes due 2028 and

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financing Arrangements and Debt (Contd.)

5.875% senior notes due 2027. Details of the Tender Offers can be found as part of the Company’s Form 8-K filed on August 1, 2022.

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

Six Months Ended
June 30,
(Thousands of dollars) 2021 2020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹ $ (104,775) 227,710
Decrease in inventories 8,938 13,968
(Increase) in prepaid expenses (1,945) (20,712)
Increase (decrease) in accounts payable and accrued liabilities ¹ 124,699 (219,228)
(Decrease) in income taxes payable (352) (403)
Net decrease in noncash operating working capital $ 26,565 1,335
Supplementary disclosures:
Cash income taxes paid, net of refunds $ 1,474 (7)
Interest paid, net of amounts capitalized of $7.4 million in 2021 and $4.9 million in 2020 80,546 100,745
Non-cash investing activities:
Asset retirement costs capitalized ² $ 6,669 6,342
Decrease in capital expenditure accrual 20,614 58,602


	Six Months Ended June 30,
(Thousands of dollars)	2022		2021
Net decrease (increase) in operating working capital, excluding cash and cash equivalents:
(Increase) in accounts receivable ¹	$	(263,104)	(104,775)
(Increase) decrease in inventories	(10,092)		8,938
(Increase) in prepaid expenses	(1,693)		(1,945)
Increase in accounts payable and accrued liabilities ¹	147,790		124,699
Increase (decrease) in income taxes payable	5,501		(352)
Net decrease (increase) in noncash operating working capital	$	(121,598)	26,565
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	1,783	1,474
Interest paid, net of amounts capitalized of $10.4 million in 2022 and $7.4 million in 2021	78,747		80,546

Non-cash investing activities:
Asset retirement costs capitalized 2	$	9,007	6,669
(Increase) decrease in capital expenditure accrual	(1,929)		20,614

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

2 2021 Excludes non-cash capitalized cost offset by Terra Nova impairment of $74.4 ~~million related to Terra Nova in 2021.~~million.

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 six-month periods ended June 30, ~~2021~~2022 and ~~2020.~~2021.


		Three Months Ended June 30,						Three Months Ended June 30,
		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	$	1,768	2,166	327	446	Service cost	$	2,129	1,768	292	327
Interest cost	Interest cost	4,300		5,763	521	794	Interest cost	5,139		4,300	574	521
Expected return on plan assets	Expected return on plan assets	(6,155)		(6,297)	0	0	Expected return on plan assets	(7,954)		(6,155)	—	—
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	156		183	0	0	Amortization of prior service cost (credit)	579		156	(133)	—
Recognized actuarial loss		5,281		4,264	(8)	0
Recognized actuarial loss (gain)							Recognized actuarial loss (gain)	3,822		5,281	(78)	(8)
Net periodic benefit expense	Net periodic benefit expense	5,350		6,079	840	1,240	Net periodic benefit expense	$	3,715	5,350	655	840
Other - curtailment		0		586	0	(1,825)
Other - special termination benefits		0		8,435	0	0
Total net periodic benefit expense		$	5,350	15,100	840	(585)

		Six Months Ended June 30,						Six Months Ended June 30,
		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	$	3,536	4,332	653	893	Service cost	$	4,258	3,536	584	653
Interest cost	Interest cost	8,586		11,554	1,042	1,588	Interest cost	10,382		8,586	1,148	1,042
Expected return on plan assets	Expected return on plan assets	(12,288)		(12,641)	0	0	Expected return on plan assets	(16,092)		(12,288)	—	—
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	312		366	0	0	Amortization of prior service cost (credit)	1,179		312	(266)	—
Recognized actuarial loss		10,560		8,533	(15)	0
Recognized actuarial loss (gain)							Recognized actuarial loss (gain)	7,644		10,560	(155)	(15)
Net periodic benefit expense	Net periodic benefit expense	$	10,706	12,144	1,680	2,481	Net periodic benefit expense	$	7,371	10,706	1,311	1,680
Other - curtailment		0		586	0	(1,825)
Other - special termination benefits		0		8,435	0	0
Total net periodic benefit expense		$	10,706	21,165	1,680	656

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

During the six-month period ended June 30, ~~2021,~~2022, the Company made contributions of ~~$19.5~~$18.4 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 ~~$22.4~~$24.4 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 ~~2017~~ Annual Incentive Plan ~~(2017 Annual Plan)~~(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

~~Table of Contents~~

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

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.

In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.

The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of ~~5 million~~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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Incentive Plans(Contd.)

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.

During the first six 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~~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.~~Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, ~~will be~~were made under the 2021 NED Plan.

During the first six 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 six-month period ended June 30, ~~2021.~~

~~Table of Contents~~

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

2022.

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


		Six Months Ended June 30,				Six Months Ended June 30,
(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	$	18,045	10,272	Compensation charged against income before tax benefit	$	34,016	18,045
Related income tax (expense) benefit recognized in income		2,478		769
Related income tax benefit recognized in income					Related income tax benefit recognized in income	5,822		2,478

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 six-month periods ended June 30, ~~2021~~2022 and ~~2020.~~2021. The following table reports the weighted-average shares outstanding used for these computations.


		Three Months Ended June 30,		Six Months Ended June 30,			Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	(Weighted-average shares)	2021	2020	2021	2020	(Weighted-average shares)	2022	2021	2022	2021
Basic method	Basic method	154,394,602	153,580,758	154,153,158	153,428,666	Basic method	155,388,555	154,394,602	155,121,098	154,153,158
Dilutive stock options and restricted stock units ¹		0	0	0	0
Dilutive stock options and restricted stock units						Dilutive stock options and restricted stock units	2,066,575	—	2,730,624	—
Diluted method	Diluted method	154,394,602	153,580,758	154,153,158	153,428,666	Diluted method	157,455,130	154,394,602	157,851,722	154,153,158

1
Due to a net loss recognized by the Company for the three-month and six-month periods ended June 30, 2021, 0 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 June 30, Six Months Ended
June 30,
2021 2020 2021 2020
Antidilutive stock options excluded from diluted shares 1,379,481 2,187,235 1,592,812 2,396,920
Weighted average price of these options $ 33.79 $ 39.24 $ 35.07 $ 40.83


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Antidilutive stock options excluded from diluted shares	—		1,379,481		234,000		1,592,812
Weighted average price of these options	$	—	$	33.79	$	49.65	$	35.07

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 six-month periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company’s effective income tax rates were as follows:


		2021	2020		2022	2021
Three months ended June 30,	Three months ended June 30,	29.3%	22.7%	Three months ended June 30,	20.4%	29.3%
Six months ended June 30,	Six months ended June 30,	25.3%	18.4%	Six months ended June 30,	20.3%	25.3%

The effective tax rate for the three-month period ended June 30, 2022 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the three-month period ended June 30, 2021 was above the ~~U.S.~~ statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of increasing the effective tax rate on an overall loss.

The effective tax rate for the ~~three-month~~six-month period ended June 30, ~~2020~~2022 was ~~higher than~~below the U.S. statutory tax rate of 21% ~~principally~~primarily due to ~~a research and development~~no tax ~~credit~~applied to the pre-tax income of the noncontrolling interest in ~~Canada,~~MP GOM offset by exploration expenses in certain foreign jurisdictions in which ~~has the impact of increasing the effective~~no income tax ~~rate.~~

~~Table of Contents~~

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

~~Note K– Income Taxes~~ benefit is currently available~~(Contd.)~~.

The effective tax rate for the six-month period ended June 30, 2021 was above the ~~U.S.~~ statutory tax rate of 21% primarily due to loss generated in Canada, which has a higher tax rate, as well as no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the six-month period ended June 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. These items reduced the tax credit on a reported pre-tax net loss.

~~The~~ Company’s tax returns in multiple jurisdictions are subject to audit by taxing 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 June 30, ~~2021,~~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 United Kingdom – 2018.~~2014. Following the ~~divestment of Malaysia~~sale in ~~the third quarter of~~ 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 six-month period ended June 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

~~At June 30, 2021, the~~The Company ~~had 45,000 barrels per day in WTI~~has entered into crude oil ~~swap financial contracts maturing through December 2021 at an average price of $42.77,~~swaps and ~~20,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2022 at an average price of $44.88.~~collar contracts. Under ~~these~~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, 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 June 30, ~~2020, the Company had 45,000 barrels~~2022, volumes per day ~~in WTI~~associated with outstanding crude oil ~~swap financial~~derivative contracts ~~maturing through~~and the ~~end of December 2020 at an~~weighted average ~~price of $56.42, and 2,000 barrels per day in WTI crude oil swap~~prices for these contracts ~~maturing from January through December 2021 at an average price of $41.54.~~are as follows:


	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 0no foreign currency exchange ~~short-term~~ derivatives outstanding at June 30, ~~2021~~2022 and ~~2020.~~2021.

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

June 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

June 30, 2022

December 31, 2021

Commodity

Accounts receivable

13,050

Accounts payable

(354,366)

Accounts payable

(89,842)

Commodity swaps

Accounts payable

(239,382)

(239,882)

Deferred credits and other liabilities

(71,259)

Deferred credits and other liabilities

(12,833)

Commodity collars

Accounts payable

(146,780)

(19,533)

Commodity collars

Accounts receivable

—

4,280

For the three-month and six-month periods ended June 30, 2022 and 2021, 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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

For the three-month and six-month periods ended June 30, 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)					Gain (Loss)
(Thousands of dollars)	(Thousands of dollars)	Statement of Operations Location		Three Months Ended June 30,				Six months ended June 30,				(Thousands of dollars)	Statement of Operations Location		Three Months Ended June 30,					Six months ended June 30,
Type of Derivative Contract	Type of Derivative Contract		2021		2020		2021		2020		Type of Derivative Contract			2022			2021		2022			2021
Commodity			(Loss) gain on crude contracts		$	(226,245)	(75,880)		$	(440,630)		324,792
Commodity swaps												Commodity swaps	Loss on crude contracts		$	(46,552)		(226,245)		$	(202,911)		(440,630)
Commodity collars												Commodity collars	Loss on crude contracts		(56,516)			—		(220,934)			—

Fair Values – Recurring

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

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


		June 30, 2021					December 31, 2020					June 30, 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 derivative contracts		$	0	0	0	0	0	13,050	0	13,050
Commodity collars											Commodity collars	$	—	—	—	—	—	4,280	—	4,280

		$	0	0	0	0	0	13,050	0	13,050		$	—	—	—	—	—	4,280	—	4,280

Liabilities:	Liabilities:										Liabilities:
Commodity swaps											Commodity swaps	$	—	239,382	—	239,382	—	239,882	—	239,882
Commodity collars											Commodity collars	—		146,780	—	146,780	—	19,533	—	19,533
Contingent consideration											Contingent consideration	—		—	244,226	244,226	—	—	196,151	196,151
Nonqualified employee savings plan	Nonqualified employee savings plan	$	17,188	0	0	17,188	14,988	0	0	14,988	Nonqualified employee savings plan	17,167		—	—	17,167	16,962	—	—	16,962
Commodity derivative contracts		0		425,625	0	425,625	0	102,675	0	102,675
Contingent consideration		0		0	209,682	209,682	0	0	133,004	133,004
		$	17,188	425,625	209,682	652,495	14,988	102,675	133,004	250,667		$	17,167	386,162	244,226	647,555	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 crude contracts in the Consolidated Statements of Operations.

The contingent consideration, related to 2018 and 2019 U.S. Gulf of Mexico acquisitions, is valued using a Monte Carlo simulation model. For the six months ended June 30, 2022 and 2021, the pre-tax income effect of changes in the fair value of the contingent consideration was an expense of $129.8 million and $76.7 million respectively and is recorded in Other operating expense in the Consolidated Statements of Operations. In the six months ended June 30, 2022, the pre-tax income effect of changes in the fair value of the contingent consideration exclude cash payments of $81.7 million, which reduced the value of the contingent consideration liability. Contingent consideration is payable annually in years 2022 to 2026.

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 pre-tax 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.

The contingent consideration, related to 2 acquisitions in 2019 and 2018, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other expense (benefit) in the Consolidated Statements of Operations. 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 0no offsetting positions recorded at June 30, ~~2021~~2022 and December 31, ~~2020.~~2021.

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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 June 30, ~~2021~~2022 and the changes during the six-month period ended June 30, ~~2021,~~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	37,842		0		0		37,842	Before reclassifications to income and retained earnings	(33,525)		—		(33,525)
Reclassifications to income	Reclassifications to income	0		8,282	¹	1,690	²	9,972	Reclassifications to income	—		6,509	¹	6,509
Net other comprehensive income (loss)	Net other comprehensive income (loss)	37,842		8,282		1,690		47,814	Net other comprehensive income (loss)	(33,525)		6,509		(27,016)
Balance at June 30, 2021		$	(286,169)	(267,350)		0		(553,519)
Balance at June 30, 2022									Balance at June 30, 2022	$	(345,420)	(209,307)		(554,727)

1 Reclassifications before taxes of ~~$10,513~~$8,256 are included in the computation of net periodic benefit expense for the six-month period ended June 30, ~~2021.~~2022. See Note H for additional information. Related income taxes of ~~$2,231~~$1,747 are included in Income tax expense (benefit) for the six-month period ended June 30, ~~2021.~~

2 Reclassifications before taxes of $2,140 are included in Interest expense, net, for the six-month period ended June 30, 2021. Related income taxes of $450 are included in Income tax expense (benefit) for the six-month period ended June 30, 2021. See Note L for additional information.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.~~ 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 ~~federal or state~~ environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not 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 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,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

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, under the Biden administration it rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.

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

~~Table of Contents~~

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

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

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.

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Total Assets at June 30, 2021 Three Months Ended June 30, 2021 Three Months Ended June 30, 2020
(Millions of dollars) External
Revenues Income
(Loss) External
Revenues Income
(Loss)
Exploration and production ¹
United States $ 6,868.2 648.9 194.7 228.3 (143.1)
Canada 2,366.7 120.6 12.7 59.2 (19.5)
Other 270.4 0 (10.4) 0 (9.0)
Total exploration and production 9,505.3 769.5 197.0 287.5 (171.6)
Corporate 1,097.7 (219.9) (223.9) (76.0) (151.6)
Continuing operations 10,603.0 549.6 (26.9) 211.5 (323.2)
Discontinued operations, net of tax 1.2 0 (0.1) 0 (1.2)
Total $ 10,604.2 549.6 (27.0) 211.5 (324.4)
Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
(Millions of dollars) External
Revenues Income
(Loss) External
Revenues Income
(Loss)
Exploration and production ¹
United States 1,139.2 313.7 739.8 (839.1)
Canada 224.6 (111.6) 148.9 (26.4)
Other 0 (17.3) 1.8 (61.3)
Total exploration and production 1,363.8 184.8 890.5 (926.8)
Corporate (434.2) (478.8) 324.8 99.8
Continuing operations 929.6 (294.0) 1,215.3 (827.0)
Discontinued operations, net of tax 0 0.1 0 (6.1)
Total 929.6 (293.9) 1,215.3 (833.1)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)


	Total Assets at June 30, 2022		Three Months Ended June 30, 2022		Three Months Ended June 30, 2021
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States	$	7,034.9	978.0	491.5	648.9	194.7
Canada	2,250.1		206.6	47.2	120.6	12.7
Other	244.9		13.7	(3.5)	—	(10.4)
Total exploration and production	9,529.9		1,198.3	535.2	769.5	197.0
Corporate	1,041.3		(97.2)	(124.8)	(219.9)	(223.9)
Continuing operations	10,571.2		1,101.1	410.4	549.6	(26.9)
Discontinued operations, net of tax	1.0		—	(0.9)	—	(0.1)
Total	$	10,572.2	1,101.1	409.5	549.6	(27.0)

			Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States			1,685.4	744.4	1,139.2	313.7
Canada			372.7	69.9	224.6	(111.6)
Other			13.7	(47.7)	—	(17.3)
Total exploration and production			2,071.8	766.6	1,363.8	184.8
Corporate			(417.8)	(421.1)	(434.2)	(478.8)
Continuing operations			1,654.0	345.5	929.6	(294.0)
Discontinued operations, net of tax			—	(1.5)	—	0.1
Total			1,654.0	344.0	929.6	(293.9)

1 Additional details about results of oil and natural gas operations are presented in the ~~table~~tables on ~~pages 26~~page 25 and ~~27.~~

~~Table of Contents~~

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

~~Note P – Leases~~

~~Nature of Leases~~

The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 19 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.

~~Related Expenses~~

~~Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:~~

Three Months Ended June 30, Six Months Ended June 30,
(Thousands of dollars) Financial Statement Category 2021 2020 2021 2020
Operating lease 1,2
Lease operating expenses $ 48,049 $ 53,588 $ 94,133 125,189
Operating lease 2
Transportation, gathering and processing 9,982 9,137 19,758 19,063
Operating lease 2
Selling and general expense 2,453 3,281 5,273 6,750
Operating lease 2
Other operating expense 2,427 4,201 4,842 4,615
Operating lease 2
Property, plant and equipment 26,738 13,104 31,634 37,660
Operating lease Impairment of assets 0 6,555 0 6,555
Finance lease
Interest on lease liabilities Interest expense, net 86 92 172 188
Sublease income Other income (662) (336) (958) (642)
Net lease expense $ 89,073 $ 89,636 $ 154,854 199,392

1 ~~Variable lease expenses.~~ The three and six months ended June 30, 2021 included variable lease expenses of $8.2 million and $13.5 million; and for the three and six months ended June 30, 2020 included variable lease expenses of $6.0 million and $12.3 million, respectively, primarily related to additional volumes processed at a gas processing plant.

2 ~~Short-term leases due within 12 months.~~The three and six months ended June 30, 2021 included $11.1 million and $23.5 million for Lease operating expense, $7.6 million and $14.9 million for Transportation, gathering and processing, $0.5 million and $1.3 million for Selling and general expense and $10.0 million and $14.9 million for Property, plant and equipment, net relating to short term leases due within 12 months. The three and six months ended June 30, 2020 included $21.4 million and $54.3 million for Lease operating expense, $6.6 million and $8.0 million for Transportation, gathering and processing, $1.0 million and $2.2 million for Selling and general expense, $7.5 million and $22.9 million for Property, plant and equipment, net, and $2.4 million for other operating expense relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.

~~Maturity of Lease Liabilities~~

(Thousands of dollars) Operating Leases Finance Leases Total
2021 $ 109,284 534 109,818
2022 185,790 1,068 186,858
2023 138,692 1,069 139,761
2024 133,502 1,069 134,571
2025 83,210 1,069 84,279
Remaining 726,103 3,472 729,575
Total future minimum lease payments 1,376,581 8,281 1,384,862
Less imputed interest (382,394) (1,403) (383,797)
Present value of lease liabilities 1
$ 994,187 6,878 1,001,065

1~~Includes both the current and long-term portion of the lease liabilities.~~26.

~~Table of Contents~~

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

~~Note P – Leases~~ ~~(Contd.)~~

~~Lease Term and Discount Rate~~


	~~June 30, 2021~~
~~Weighted average remaining lease term:~~
~~Operating leases~~	~~11 years~~
~~Finance leases~~	~~8 years~~
~~Weighted average discount rate:~~
~~Operating leases~~	~~5.4~~	%
~~Finance leases~~	~~4.7~~	%

~~Other Information~~

Six Months Ended June 30,
(Thousands of dollars) 2021 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 87,768 $ 90,831
Operating cash flows from finance leases 172 188
Financing cash flows from finance leases 371 336
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases ¹ $ 94,788 277,662

1The six months ended June 30, 2021 includes $90.3 million related to an offshore drilling rig with a lease term of 16 months. The six months ended June 30, 2020 includes $268.8 million related to a 5-year lease for the Cascade/Chinook FPSO in the U.S. Gulf of Mexico.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

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

Similar to the overall inflation in the wider economy, the oil and gas industry, and hence ~~volatility~~the Company, is observing higher costs for goods and services used in ~~current~~exploration and ~~future prices for Murphy’s product.~~

~~In the current quarter and first half of 2021, overall energy demand has recovered significantly compared to 2020. The OPEC+ group of oil producing countries (OPEC+)~~production operations. Murphy continues to ~~constrain~~manage input costs through its dedicated procurement department focused on managing supply however these are being gradually scaled back as 2021 progresses. OPEC+ last year 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 June 2021. From July to December 2021 OPEC+ has reported it will increase supply by a 0.4 million bpd a month, with aims to fully phase out cuts by September 2022.

~~Overall the combination of OPEC+ supply constraints~~chain and the increase in demand driven by the global COVID-19 vaccine roll out has provided upwards 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 June 30, ~~2021,~~2022, West Texas Intermediate (WTI) crude oil prices averaged approximately ~~$66~~$108.41 per barrel (compared to ~~$58~~$94.29 in the first quarter of ~~2021~~2022 and ~~$28~~$66.07 in the second quarter of ~~2020)~~2021). The ~~closing~~average price for WTI ~~at the end~~in June of ~~the second quarter of 2021~~2022 was approximately ~~$71~~$114.34 per barrel, reflecting a ~~52%~~60% increase from June of 2021 and a 6% increase from the average price ~~at the end~~from March of ~~2020 and a 14% increase from the first quarter 2021 closing price.~~2022. The average price in July ~~2021~~2022 was ~~$72.43~~$99.38 per barrel. As of close on August ~~3, 2021,~~2, 2022, the NYMEX WTI forward curve ~~price~~prices for the remainder of ~~2021~~2022 and ~~2022~~2023 were ~~$69.71~~$92.82 and ~~$65.34~~$86.14 per barrel, respectively.

For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the GOM Kodiak field. The Company reported net income from continuing operations of $410.4 million for the three months ended June 30, 2022; this amount includes income attributable to noncontrolling interest of $58.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $69.6 million and after-tax losses on contingent consideration of $25.1 million.

In the second quarter of 2022, the Company achieved first production from the first four wells at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico; with production flowing through the Murphy-operated King’s Quay floating production and storage facility.

In June 2022, the Company acquired an additional 11.0% working interest (there is no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million.

For the three months ended June 30, 2021, the Company produced 182 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing ~~operations. The Company~~operations and invested $207.1 million in capital expenditures (on a value of work done basis) ~~in the three months ended June 30, 2021.~~. The Company reported net loss from continuing operations of $26.9 million for the ~~three months ended June 30,~~second quarter of 2021. This amount ~~includes~~included income attributable to noncontrolling interest of $36.0 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $103.3 million and $48.8 million, respectively.

For the six months ended June 30, 2021, the Company produced 174 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $458.2 million in capital expenditures (on a value of work done basis) in the six months ended June 30, 2021, which included $17.3 million to fund the development of the King’s Quay Floating Production System (FPS). The FPS capital expenditures were reimbursed by Arclight inIn the first quarter of 2021, (see below). The Company reported net loss from continuing operations of $294.0 million for the six months ended June 30, 2021. This amount includes income attributable to noncontrolling interest of $56.7 million, after-tax impairment charges of $128.0 million, and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $224.6 million and $60.6 million, respectively.

For the three months ended June 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $179.6 million in capital expenditures (on a value of work done basis), in the second quarter of 2020, which included $32.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $323.1 million for the second quarter of 2020. This amount included loss attributable to noncontrolling interest of $7.2 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions of $145.8 million.

For the six months ended June 30, 2020, the Company produced 189 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $557.6 million in capital expenditures (on a value of work done basis) for the six months ended June 30, 2020, which included $61.4 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $827.0 million for the six months ended June 30, 2020. This amount included loss attributable to noncontrolling interest of $99.8 million, after-tax impairment charges of $708.3 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions of $137.3 million.

During the six months ended June 30, 2021, crude oil and condensate volumes from continuing operations were lower than the prior year period. The decrease in production volumes is due to reduced capital expenditures throughout 2020 and the first

~~Table of Contents~~

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

~~Summary (contd.)~~

quarter of 2021 to support generating positive free cash flow. Revenue from sales to customers was 52% higher during the first half of 2021 compared to the first half of 2020, primarily driven by the change in price.

~~In the first half of 2021,~~ the Company’s subsidiary, ~~"Murphy~~Murphy Exploration & Production Company ~~USA"~~- 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.

~~Also,~~For the six months ended June 30, 2022, the Company produced 162 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $621.9 million in capital expenditures (on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat exploration well in Brazil deferred from 2021). The Company reported net income from continuing operations of $345.5 million for the six months ended June 30, 2022. This amount includes income attributable to noncontrolling interest of $106.8 million and after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration of $79.3 million and $102.3 million, respectively.

For the six months ended June 30, 2021, the Company produced 174 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $458.2 million in capital expenditures (on a value of work done basis), which included $17.3 million to fund the development of the King’s Quay floating production system (which was subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of $294.0 million for the six months ended June 30, 2021. This amount included income attributable to noncontrolling interest of $56.7 million, after-tax impairment charges of $128.0 million and after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration of $224.6 million and $60.6 million, respectively.

Table of Contents

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

Summary (contd.)

During the six months ended June 30, 2022, crude oil and condensate volumes from continuing operations were lower than the prior year period. The decrease in production volumes is due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders. Revenue from production was 47% higher during the first half of 2022 compared to the first half of 2021, primarily driven by the ~~Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing~~increase in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which includes 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 incurred closing costs of $8.0 million. The proceeds from issue are reported net of costs to issue on the balance sheet.price.

Results of Operations

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


		Income (Loss)						Income (Loss)
		Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2021		2020	2021	2020	(Millions of dollars)	2022		2021	2022		2021
Exploration and production	Exploration and production	$	197.0	(171.6)	184.8	(926.8)	Exploration and production	$	535.2	197.0	$	766.6	184.8
Corporate and other	Corporate and other	(223.9)		(151.6)	(478.8)	99.8	Corporate and other	(124.8)		(223.9)	(421.1)		(478.8)
(Loss) income from continuing operations		(26.9)		(323.2)	(294.0)	(827.0)
Income (loss) from continuing operations							Income (loss) from continuing operations	410.4		(26.9)	345.5		(294.0)
Discontinued operations ¹	Discontinued operations ¹	(0.1)		(1.2)	0.1	(6.1)	Discontinued operations ¹	(0.9)		(0.1)	(1.5)		0.1
Net (loss) income including noncontrolling interest		$	(27.0)	(324.4)	(293.9)	(833.1)
Net income (loss) including noncontrolling interest							Net income (loss) including noncontrolling interest	$	409.5	(27.0)	$	344.0	(293.9)

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 June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2021		2020	2021	2020	(Millions of dollars)	2022		2021	2022		2021
Exploration and production	Exploration and production						Exploration and production
United States	United States	$	194.7	(143.1)	313.7	(839.1)	United States	$	491.5	194.7	$	744.4	313.7
Canada	Canada	12.7		(19.5)	(111.6)	(26.4)	Canada	47.2		12.7	69.9		(111.6)
Other	Other	(10.4)		(9.0)	(17.3)	(61.3)	Other	(3.5)		(10.4)	(47.7)		(17.3)
Total	Total	$	197.0	(171.6)	184.8	(926.8)	Total	$	535.2	197.0	$	766.6	184.8

2423

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) ~~income~~ 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 June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
(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	2022		2021
Net loss attributable to Murphy (GAAP)		$	(63.1)	(317.1)	(350.5)	(733.2)
Income tax benefit		(11.2)		(94.8)	(99.3)	(186.3)
Net income (loss) attributable to Murphy (GAAP)							Net income (loss) attributable to Murphy (GAAP)	$	350.6	(63.1)	$	237.2	(350.5)
Income tax expense (benefit)							Income tax expense (benefit)	105.1		(11.2)	88.1		(99.3)
Interest expense, net	Interest expense, net	43.4		38.6	131.5	79.7	Interest expense, net	41.4		43.4	78.7		131.5
Depreciation, depletion and amortization expense ¹	Depreciation, depletion and amortization expense ¹	217.3		219.1	405.6	505.3	Depreciation, depletion and amortization expense ¹	188.2		217.3	344.8		405.6
EBITDA attributable to Murphy (Non-GAAP)	EBITDA attributable to Murphy (Non-GAAP)	186.4		(154.2)	87.3	(334.5)	EBITDA attributable to Murphy (Non-GAAP)	685.3		186.4	748.8		87.3
Mark-to-market loss (gain) on crude oil derivative contracts		130.9		184.5	284.4	(173.8)
Mark-to-market (gain) loss on derivative instruments							Mark-to-market (gain) loss on derivative instruments	(88.1)		130.9	100.4		284.4
Mark-to-market loss on contingent consideration							Mark-to-market loss on contingent consideration	31.7		61.8	129.8		76.7
Accretion of asset retirement obligations ¹							Accretion of asset retirement obligations ¹	10.2		9.5	20.7		20.0
Discontinued operations loss (income)							Discontinued operations loss (income)	0.9		0.1	1.5		(0.1)
Foreign exchange (gain) loss							Foreign exchange (gain) loss	(8.0)		—	(8.0)		1.3
Impairment of assets ¹	Impairment of assets ¹	—		19.6	171.3	886.0	Impairment of assets ¹	—		—	—		171.3
Mark-to-market loss (gain) on contingent consideration		61.8		15.7	76.7	(43.5)
Accretion of asset retirement obligations ¹		9.5		10.5	20.0	20.4
Unutilized rig charges	Unutilized rig charges	2.5		4.5	5.3	8.0	Unutilized rig charges	—		2.5	—		5.3
Foreign exchange losses (gains)		—		1.4	1.3	(3.3)
Discontinued operations (income) loss		0.1		1.2	(0.1)	6.1
Restructuring expenses		—		41.4	—	41.4
Inventory loss		—		—	—	4.8

Adjusted EBITDA attributable to Murphy (Non-GAAP)	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	391.2	124.6	646.2	411.6	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	632.0	391.2	$	993.2	646.2

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)	15,648		15,242	29,318	32,312	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	14,884		15,648	27,449		29,318

Adjusted EBITDA per barrel of oil equivalents sold	Adjusted EBITDA per barrel of oil equivalents sold	$	25.00	8.17	22.04	12.74	Adjusted EBITDA per barrel of oil equivalents sold	$	42.46	25.00	$	36.18	22.04

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 JUNE 30, 2022 AND 2021


(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended June 30, 2022
Oil and gas sales and other operating revenues	$	977.8	156.8	13.7	1,148.3
Sales of purchased natural gas	0.2		49.8	—	50.0
Lease operating expenses	109.5		36.9	0.9	147.3
Severance and ad valorem taxes	17.3		0.3	—	17.6
Transportation, gathering and processing	32.3		17.6	—	49.9
Costs of purchased natural gas	0.2		47.7	—	47.9
Depreciation, depletion and amortization	153.7		35.6	3.4	192.7

Accretion of asset retirement obligations	9.1		2.4	0.1	11.6
Exploration expenses
Dry holes and previously suspended exploration costs	(0.7)		—	2.0	1.3
Geological and geophysical	—		0.1	0.8	0.9
Other exploration	2.9		0.3	6.0	9.2
	2.2		0.4	8.8	11.4
Undeveloped lease amortization	2.3		—	1.4	3.7
Total exploration expenses	4.5		0.4	10.2	15.1
Selling and general expenses	3.2		3.8	2.1	9.1
Other	35.3		(2.3)	—	33.0
Results of operations before taxes	612.9		64.2	(3.0)	674.1
Income tax provisions	121.4		17.0	0.5	138.9
Results of operations (excluding Corporate segment)	$	491.5	47.2	(3.5)	535.2

Three Months Ended June 30, 2021
Oil and gas sales and other operating revenues	$	648.9	120.6	—	769.5

Lease operating expenses	90.5		35.8	—	126.3
Severance and ad valorem taxes	10.9		0.5	—	11.4
Transportation, gathering and processing	33.6		16.1	—	49.7

Depreciation, depletion and amortization	180.0		43.5	0.5	224.0
Accretion of asset retirement obligations	9.2		3.0	—	12.2

Exploration expenses
Dry holes and previously suspended exploration costs	(0.1)		—	—	(0.1)
Geological and geophysical	2.1		—	0.8	2.9
Other exploration	2.3		0.1	4.1	6.5
	4.3		0.1	4.9	9.3
Undeveloped lease amortization	2.5		—	1.8	4.3
Total exploration expenses	6.8		0.1	6.7	13.6
Selling and general expenses	5.3		3.9	2.1	11.3
Other	72.9		0.9	0.3	74.1
Results of operations before taxes	239.7		16.8	(9.6)	246.9
Income tax provisions	45.0		4.1	0.8	49.9
Results of operations (excluding Corporate segment)	$	194.7	12.7	(10.4)	197.0

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

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – ~~THREE~~SIX MONTHS ENDED JUNE 30, ~~2021~~2022 AND ~~2020~~2021


(Millions of dollars)	(Millions of dollars)	United States 1		Canada	Other	Total	(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended June 30, 2021
Six Months Ended June 30, 2022							Six Months Ended June 30, 2022
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	648.9	120.6	—	769.5	Oil and gas sales and other operating revenues	$	1,685.2	286.1	13.7	1,985.0
Sales of purchased natural gas							Sales of purchased natural gas	0.2		86.6	—	86.8
Lease operating expenses	Lease operating expenses	90.5		35.8	—	126.3	Lease operating expenses	209.4		73.8	0.9	284.1
Severance and ad valorem taxes	Severance and ad valorem taxes	10.9		0.5	—	11.4	Severance and ad valorem taxes	31.5		0.7	—	32.2
Transportation, gathering and processing	Transportation, gathering and processing	33.6		16.1	—	49.7	Transportation, gathering and processing	61.5		35.3	—	96.8
Costs of purchased natural gas							Costs of purchased natural gas	0.2		81.4	—	81.6
Depreciation, depletion and amortization	Depreciation, depletion and amortization	180.0		43.5	0.5	224.0	Depreciation, depletion and amortization	280.2		69.8	3.5	353.5
Accretion of asset retirement obligations							Accretion of asset retirement obligations	18.5		4.9	0.1	23.5

Accretion of asset retirement obligations		9.2		3.0	—	12.2
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	(0.1)		—	—	(0.1)	Dry holes and previously suspended exploration costs	(0.7)		—	34.8	34.1
Geological and geophysical	Geological and geophysical	2.1		—	0.8	2.9	Geological and geophysical	2.6		0.1	1.0	3.7
Other exploration	Other exploration	2.3		0.1	4.1	6.5	Other exploration	4.4		0.4	12.1	16.9
		4.3		0.1	4.9	9.3		6.3		0.5	47.9	54.7
Undeveloped lease amortization	Undeveloped lease amortization	2.5		—	1.8	4.3	Undeveloped lease amortization	4.7		0.1	3.2	8.0
Total exploration expenses	Total exploration expenses	6.8		0.1	6.7	13.6	Total exploration expenses	11.0		0.6	51.1	62.7
Selling and general expenses	Selling and general expenses	5.3		3.9	2.1	11.3	Selling and general expenses	11.5		8.9	4.5	24.9
Other	Other	72.9		0.9	0.3	74.1	Other	138.1		2.8	0.4	141.3
Results of operations before taxes	Results of operations before taxes	239.7		16.8	(9.6)	246.9	Results of operations before taxes	923.5		94.5	(46.8)	971.2
Income tax provisions (benefits)	Income tax provisions (benefits)	45.0		4.1	0.8	49.9	Income tax provisions (benefits)	179.1		24.6	0.9	204.6
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	194.7	12.7	(10.4)	197.0	Results of operations (excluding Corporate segment)	$	744.4	69.9	(47.7)	766.6

Three Months Ended June 30, 2020
Six months ended June 30, 2021							Six months ended June 30, 2021
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	228.3	59.2	—	287.5	Oil and gas sales and other operating revenues	$	1,139.2	224.6	—	1,363.8

Lease operating expenses	Lease operating expenses	116.8		27.4	0.5	144.7	Lease operating expenses	206.6		66.6	0.3	273.5
Severance and ad valorem taxes	Severance and ad valorem taxes	6.1		0.4	—	6.5	Severance and ad valorem taxes	19.8		0.8	—	20.6
Transportation, gathering and processing	Transportation, gathering and processing	31.5		9.6	—	41.1	Transportation, gathering and processing	62.1		30.5	—	92.6

Depreciation, depletion and amortization	Depreciation, depletion and amortization	175.8		49.7	0.5	226.0	Depreciation, depletion and amortization	329.6		88.3	1.0	418.9
Accretion of asset retirement obligations	Accretion of asset retirement obligations	9.1		1.3	—	10.4	Accretion of asset retirement obligations	18.2		4.5	—	22.7
Impairment of assets	Impairment of assets	19.6		—	—	19.6	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	7.6		—	—	7.6	Dry holes and previously suspended exploration costs	0.6		—	—	0.6
Geological and geophysical	Geological and geophysical	8.0		0.1	0.5	8.6	Geological and geophysical	2.7		—	1.0	3.7
Other exploration	Other exploration	2.9		0.1	3.0	6.0	Other exploration	2.9		0.1	9.1	12.1
		18.5		0.2	3.5	22.2		6.2		0.1	10.1	16.4
Undeveloped lease amortization	Undeveloped lease amortization	4.8		—	2.4	7.2	Undeveloped lease amortization	4.8		0.1	4.0	8.9
Total exploration expenses	Total exploration expenses	23.3		0.2	5.9	29.4	Total exploration expenses	11.0		0.2	14.1	25.3
Selling and general expenses	Selling and general expenses	7.6		5.4	2.3	15.3	Selling and general expenses	10.8		8.0	3.5	22.3
Other	Other	24.2		(1.2)	0.1	23.1	Other	94.4		4.0	(3.2)	95.2
Results of operations before taxes	Results of operations before taxes	(185.7)		(33.6)	(9.3)	(228.6)	Results of operations before taxes	386.7		(149.6)	(15.7)	221.4
Income tax provisions (benefits)	Income tax provisions (benefits)	(42.6)		(14.1)	(0.3)	(57.0)	Income tax provisions (benefits)	73.0		(38.0)	1.6	36.6
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	(143.1)	(19.5)	(9.0)	(171.6)	Results of operations (excluding Corporate segment)	$	313.7	(111.6)	(17.3)	184.8

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

Table of Contents

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

Results of Operations (contd.)

~~OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2021 AND 2020~~

(Millions of dollars)
United
States 1
Canada Other Total
Six Months Ended June 30, 2021
Oil and gas sales and other operating revenues $ 1,139.2 224.6 — 1,363.8
Lease operating expenses 206.6 66.6 0.3 273.5
Severance and ad valorem taxes 19.8 0.8 — 20.6
Transportation, gathering and processing 62.1 30.5 — 92.6
Depreciation, depletion and amortization 329.6 88.3 1.0 418.9
Accretion of asset retirement obligations 18.2 4.5 — 22.7
Impairment of assets — 171.3 — 171.3
Exploration expenses
Dry holes and previously suspended exploration costs 0.6 — — 0.6
Geological and geophysical 2.7 — 1.0 3.7
Other exploration 2.9 0.1 9.1 12.1
6.2 0.1 10.1 16.4
Undeveloped lease amortization 4.8 0.1 4.0 8.9
Total exploration expenses 11.0 0.2 14.1 25.3
Selling and general expenses 10.8 8.0 3.5 22.3
Other 94.4 4.0 (3.2) 95.2
Results of operations before taxes 386.7 (149.6) (15.7) 221.4
Income tax provisions (benefits) 73.0 (38.0) 1.6 36.6
Results of operations (excluding Corporate segment) $ 313.7 (111.6) (17.3) 184.8
Six months ended June 30, 2020
Oil and gas sales and other operating revenues $ 739.8 148.9 1.8 890.5
Lease operating expenses 295.0 58.0 0.8 353.8
Severance and ad valorem taxes 15.2 0.7 — 15.9
Transportation, gathering and processing 66.1 19.4 — 85.5
Depreciation, depletion and amortization 423.3 101.7 1.0 526.0
Accretion of asset retirement obligations 17.7 2.7 — 20.4
Impairment of assets 947.4 — 39.7 987.1
Exploration expenses
Dry holes and previously suspended exploration costs 7.7 — — 7.7
Geological and geophysical 9.3 0.1 4.2 13.6
Other exploration 3.7 0.3 9.5 13.5
20.7 0.4 13.7 34.8
Undeveloped lease amortization 9.9 0.2 4.6 14.7
Total exploration expenses 30.6 0.6 18.3 49.5
Selling and general expenses 11.3 9.8 3.9 25.0
Other (21.5) (1.0) (1.1) (23.6)
Results of operations before taxes (1,045.3) (43.0) (60.8) (1,149.1)
Income tax provisions (benefits) (206.2) (16.6) 0.5 (222.3)
Results of operations (excluding Corporate segment) $ (839.1) (26.4) (61.3) (926.8)

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

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

Exploration and Production

Second 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 $491.5 million in the second quarter of 2022 compared to income of $194.7 million in the second quarter of ~~2021 compared to a loss of $143.1 million in the second quarter of 2020.~~2021. Results were ~~$337.8~~$296.8 million favorable in the ~~2021~~2022 quarter compared to the ~~2020~~2021 period primarily due to higher revenues ($~~420.6~~328.9 million), lower ~~lease~~depreciation, depletion and amortization (DD&A, $26.3 million) and other operating ~~expenses~~expense ($~~26.3 million), lower impairment charge ($19.6 million), and general and administrative expenses (G&A: $2.3~~37.6 million), partially offset by higher income tax expense ($~~87.6~~76.4 million), ~~other~~and lease operating expense ($~~48.7 million) and depreciation, depletion and amortization ($4.2~~19.0 million). Higher revenues were primarily due to higher commodity prices, ~~higher~~partially off-set by lower volumes. Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions primarily in the Eagle Ford ~~Shale volumes (due~~Shale. Lower other operating expense is primarily due to ~~higher capital expenditures), and higher volumes in the U.S.~~lower unfavorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM)~~, due to a 3.5% working interest acquisition~~ acquisitions that occurred in the ~~Lucius field. Lower lease operating expense was primarily attributable to well workers in the GOM in 2020. Lower G&A is due to cost reductions and lower headcount as a result~~second quarter of ~~restructuring (primarily closing the El Dorado and Calgary offices in 2020).~~2021. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher ~~other~~lease operating expense is ~~primarily~~ due to ~~unfavorable mark~~cost increases from inflationary pressures (mainly at our onshore businesses), higher severance taxes at Eagle Ford (due to ~~market revaluation on contingent consideration (as a result of~~ higher commodity prices) ~~from prior Gulf of Mexico (GOM) acquisitions.~~and costs related to first production at the Khaleesi asset flowing to the King’s Quay facility.

Canadian E&P operations reported earnings of $47.2 million in the second quarter 2022 compared to income of $12.7 million in the second quarter ~~2021 compared to a loss~~ of ~~$19.5 million in the second quarter of 2020.~~2021. Results were favorable ~~$32.2~~$34.5 million compared to the ~~2020~~2021 period primarily due to higher ~~revenue~~revenues from production ($~~61.4~~36.2 million) and lower ~~depreciation and amortization~~DD&A ($~~6.2~~7.9 million), partially offset by higher tax expense ($~~18.2 million), higher lease operating expenses ($8.4 million), higher transportation, gathering, and processing expenses ($6.5 million), and lower other operating income ($2.1~~12.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas ~~prices~~volumes at Tupper ~~Montney and higher oil prices at Hibernia and Kaybob Duvernay.~~Montney. Lower ~~depreciation expense~~DD&A is due primarily to lower production volumes at Kaybob Duvernay due to normal well decline. Higher ~~lease operating and transportation, gathering and processing costs are~~income tax expense is a result of pre-tax profits principally due to ~~higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in~~ the ~~future.~~recovering oil price.

Other international E&P operations reported a loss from continuing operations of $3.5 million in the second quarter of 2022 compared to a loss of $10.4 million in the second quarter of ~~2021 compared to a loss of $9.0 million in the second quarter of 2020.~~2021. The result was ~~$1.4~~$6.9 million ~~unfavorable~~favorable in the ~~2021~~2022 period versus ~~2020~~2021 primarily due to higher ~~exploration expenses and income tax expense.~~revenue from Brunei.

Six months ~~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 $744.4 million in the first six months of 2022 compared to earnings of $313.7 million in the first six months of ~~2021 compared to a loss of $839.1 million in the first six months of 2020.~~2021. Results were ~~$1,152.8~~$430.7 million favorable in the ~~2021 quarter~~2022 period compared to the ~~2020~~2021 period, ~~primarily due to no impairment charges in the current period (2020: $947.4 million). Further, the change year over year is~~ driven by higher revenues ($~~399.4 million), lower depreciation, depletion and amortization (DD&A: $93.7 million), lower lease operating expenses (LOE: $88.4 million), lower transportation, gathering, and processing charges ($4.0~~546.0 million) and lower GDD&A ($~~0.5~~49.4 million), partially offset by higher income tax expense ($~~279.2~~106.1 million) and higher other operating expense ($~~115.9~~43.7 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 decreased 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.~~2021, offset by 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 lease operating expenses were primarily due to higher Gulf of Mexico workover costs in the prior year at Cascade ($49.3 million)lower production volumes and ~~Dalmatian ($20.5 million).~~lower rates driven by positive reserve revisions. Higher income tax expense is a result of higher pre-tax ~~profits principally due to the recovering oil price and lower DD&A and LOE.~~income. Higher other operating expense is primarily due to ana higher unfavorable mark to market revaluation on contingent consideration ($~~76.7~~129.8 million; as a result of higher commodity prices) from prior ~~Gulf of Mexico (GOM)~~GOM acquisitions.

Canadian E&P operations reported earnings of $69.9 million in the first six months of 2022 compared to a loss of $111.6 million in the first six months of ~~2021 compared to a loss of $26.4 million in the first six months quarter of 2020.~~2021. Results were ~~$85.2~~$181.5 million ~~unfavorable~~favorable compared to the ~~2020 period primarily due to~~2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and prior to the subsequent sanctioning of an asset life extension project in the third quarter of 2021. The current ~~period, partially offset by~~year results also include higher revenue from production ($~~75.7~~61.5 million)~~, higher income tax benefit ($21.4 million),~~ and lower DD&A ($~~13.4~~18.5 million)~~. The impairment charge in the current year is due to the status, including agreements with the partners, of~~ offset by higher income tax expense ($62.6 million), lease operating expenses ($7.2 million) and ~~production plans at Terra Nova as of June 30, 2021. During the second quarter, partners continued to negotiate on an agreement to restructure the Terra Nova project ownership~~transportation, gathering and ~~renew the asset life extension project.~~processing costs ($4.8 million). Higher revenue is primarily attributable to higher realized prices (oil and condensate, natural gas ~~prices~~and NGLs). Lower DD&A is primarily due to lower production volumes at ~~Tupper Montney and higher oil prices at Hibernia and~~ Kaybob ~~Duvernay.~~Duvernay due to normal well decline. Higher income tax ~~benefit~~expense is a result of a higher pre-tax ~~loss driven by~~income principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity. Higher capacity is expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss of $47.7 million in the first six months of 2022 compared to a loss of $17.3 million in the prior year. Results were $30.4 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1

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Results of Operations (contd.)

~~charge. Lower DD&A is a result of lower sales volume at Kaybob Duvernay following reduced capital expenditures throughout 2020.~~

~~Other international E&P operations reported a loss of $17.3 million~~exploration well in block SEAL-M-428 in the ~~first six months of 2021 compared to a loss of $61.3 million in the prior year. Results~~Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were ~~$44.0 million favorable compared to the 2020 period primarily due to an impairment charge of $39.7 million in the prior year.~~

discovered.

Corporate

Second quarter ~~2021~~2022 vs. ~~2020~~2021

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative ~~commodity contracts (typically forward~~instruments (forward swaps ~~to hedge/fix the price of oil sold)~~ and corporate overhead not allocated to Exploration and Production, reported a net loss of $223.9 million in the second quarter 2021 compared to net loss of $151.6 million in the 2020 quarter. The $72.3 million unfavorable variance is principally due to higher losses on forward swap commodity contracts in 2021 compared to the 2020 period (2021: $226.2 million loss; 2020: $75.9 million loss). This is partially offset by lower restructuring charges ($41.4 million), higher tax benefits ($23.2 million), lower G&A ($6.1 million) and lower DD&A ($2.3 million). Losses on forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with a fixed price. Lower restructuring charges and G&A expenditures are due to the 2020 cost reduction efforts which included closing its 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.

~~Six months 2021 vs. 2020~~

~~Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative commodity contracts (typically forward swaps~~collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of ~~$478.8~~$124.8 million in the ~~first six months~~second quarter of ~~2021~~2022 compared to ~~earnings~~a loss of ~~$99.8~~$223.9 million in the ~~first six months~~second quarter of ~~2020.~~2021. The ~~$578.6~~$99.1 million ~~unfavorable~~favorable variance is ~~primarily~~principally due to ~~realized and unrealized~~lower losses on ~~forward swap commodity contracts~~derivative instruments in ~~2021~~2022 ($123.2 million) compared to ~~gains in 2020 (2021: $440.6~~the 2021 period (2022: $103.1 million loss; ~~2020: $324.8~~2021: $226.2 million ~~gain), and higher interest expense ($50.7 million)~~loss), partially offset by higher tax ~~benefits~~expense ($~~171.9 million), lower restructuring charges ($41.4 million), lower G&A ($14.6 million) and lower DD&A ($5.0~~27.3 million). Realized and unrealized losses on ~~forward swap commodity contracts~~derivative instruments are due to ~~higher market (West Texas Intermediate)~~an increase in oil prices for current (realized) and future (unrealized) periods whereby the ~~contract provides~~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 June 30, ~~2021,~~2022, the average forward NYMEX WTI price for the remainder of ~~2021 was $71.80 and for~~ 2022 was ~~$66.38~~$100.49 (versus swap contract fixed hedge ~~prices~~price of ~~$42.77 and $44.88, respectively)~~$44.88). ~~Interest charges are higher in 2021primarily due an early redemption premium incurred by~~The swap contracts provide the Company ~~upon~~with a fixed price and the ~~early retirement of the notes originally due June~~collar contracts provide for a minimum (floor) and ~~December 2022.~~a maximum (ceiling) price. Higher income tax ~~benefits are~~benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on ~~forward swap commodity contracts. Lower restructuring~~derivative instruments.

Six months 2022 vs. 2021

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 the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $421.1 million in the first six months of 2022 compared to a loss of $478.8 million in the first six months of 2021. The $57.7 million favorable variance is primarily due to lower interest expense ($60.1 million) and lower losses on derivative instruments in 2022 ($16.8 million) compared to 2021 (2022: $423.8 million loss; 2021: $440.6 million loss), partially offset by lower tax benefits ($19.5 million). Interest charges are lower in the first six months of 2022primarily due to lower debt redemption premiums ($3.4 million in 2022; $34.2 million in 2021) incurred by the Company and ~~G&A expenditures~~lower overall debt. In the first six months of 2022 the Company redeemed $200.0 million of notes compared to the 2021 redemption of $576.4 million. Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) periods whereby the ~~2020 cost reduction efforts which included closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta,~~swap contracts provide the Company with a fixed price and ~~consolidating all worldwide staff activities to its existing office location in Houston, Texas.~~the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of June 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $100.49 (versus swap contract fixed hedge price of $44.88). Lower income tax benefit is a result of lower pre-tax losses.

Production Volumes and Prices

Second quarter ~~2021~~2022 vs. ~~2020~~2021

Total hydrocarbon production from continuing operations averaged ~~182,050~~173,173 barrels of oil equivalent per day in the second quarter of ~~2021,~~2022, which ~~represented a 1% increase from~~was 5% lower than the ~~179,506~~182,050 barrels per day produced in second quarter ~~2020.~~2021. The ~~increase~~decrease in production ~~volumes~~ is principally due to ~~increased production~~an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders; partially offset by first oil from the Khaleesi, Mormont, Samurai field development project in the ~~U.S. offset by lower production in Canada.~~second quarter.

Average crude oil and condensate production from continuing operations was 98,661 barrels per day in the second quarter of 2022 compared to 109,327 barrels per day in the second quarter of ~~2021 compared to 108,712 barrels per day in the second quarter~~2021. The decrease of ~~2020. The increase of 615~~10,666 barrels per day was associated with ~~higher Eagle Ford Shale production (3,267 barrels per day higher at Karnes due to 2021 capital expenditures in this area), higher~~lower volumes in the Gulf of Mexico ~~(1,466~~(5,041 barrels per ~~day~~day) principally due to ~~a 3.5% working interest acquisition in Lucius field),~~the focused effort to reduce capital expenditures and several planned downtime events at St. Malo and Chinook, partially offset by first production from the first four wells at the Khaleesi, Mormont, Samurai development. Canada production is lower ~~volumes in Canada (4,477~~(1,700 barrels per ~~day lower~~day) primarily attributable to Kaybob Duvernay well ~~decline).~~decline and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (4,949 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$65.57~~$109.25 per barrel in the second quarter ~~2021~~2022 compared to ~~$23.03~~$65.57 per barrel in the ~~2020~~2021 period, an increase of ~~185%~~67% quarter over quarter.

Total production of natural gas liquids (NGL) from continuing operations was ~~11,252~~10,950 barrels per day in the second quarter ~~2021~~2022 compared to ~~11,540~~11,252 barrels per day in the ~~2020~~2021 period. The average sales price for U.S. NGL was $39.37 per barrel in the 2022 quarter compared to $22.18 per barrel in ~~the 2021 quarter compared to $7.67 per barrel in 2020.~~2021. The average sales price for NGL in Canada was ~~$30.63~~$63.99 per barrel in the ~~2021~~2022

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Results of Operations (contd.)

quarter compared to ~~$13.78~~$30.63 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 ~~369~~381.4 million cubic feet per day (MMCFD) in the second quarter ~~2021~~2022 compared to ~~356~~368.8 MMCFD in ~~2020.~~2021. The increase of 1312.5 MMCFD was a result of higher volumes in Canada (8(20.8 MMCFD), partially offset by lower volumes in the Gulf of Mexico ~~(3 MMCFD) and in the Eagle Ford Shale (2~~(8.3 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 1015 new wells at Tupper Montney in the second quarter of ~~2021. Higher volumes in the Gulf of Mexico are principally due to higher natural gas volumes at Lucius and Neidermeyer.~~2022.

Natural gas prices for the total Company averaged ~~$2.34~~$3.90 per thousand cubic feet (MCF) in the ~~2021~~2022 quarter, versus ~~$1.54~~$2.34 per MCF average in the same quarter of ~~2020.~~2021. Average natural gas prices in the U.S. and Canada in the quarter were ~~$2.61~~$7.37 and ~~$2.23~~$2.78 per MCF, respectively.

Six months ~~2021~~2022 vs. ~~2020~~2021

Total hydrocarbon production from ~~all E&P continuing operations~~Exploration and Production averaged ~~173,762~~161,579 barrels of oil equivalent per day in the first six months of ~~2021,~~2022, which represented a 8%7.0% decrease from the ~~189,350~~173,762 barrels per day produced in the first six months of ~~2020.~~2021. The decrease in production is principally due to ~~lower~~an ongoing focused effort to reduce capital expenditures ~~throughout~~that began in 2020 to ~~support generating positive free cashflow.~~prioritize corporate debt reduction and return funds to shareholders.

Average crude oil and condensate production ~~from continuing operations~~ was 91,154 barrels per day in the first six months of 2022 compared to 103,434 barrels per day in the first six months of ~~2021 compared to 115,396 barrels per day in the first six months of 2020.~~2021. The decrease of ~~11,962~~12,280 barrels per day was principally due to lower Gulf of Mexico production ~~(6,439~~(7,064 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 St. Malo, Front Runner, Habanero and Chinook. Canada production is lower (2,434 barrels per day) due to normal field decline at Kaybob and temporary operational issues at ~~the Cascade & Chinook and Kodiak fields in the first quarter of 2021 (these operational issues are now resolved), offset by higher second quarter~~Hibernia. Eagle Ford Shale production ~~at Lucius.~~is lower (3,400 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$62.14~~$102.86 per barrel in the first six months of ~~2021~~2022 compared to ~~$35.65~~$62.14 per barrel in the ~~2020~~2021 period, an increase of ~~74%~~65.5% year over year.

Total production of natural gas liquids (NGL) ~~from continuing operations~~ was ~~10,552~~10,150 barrels per day in the first six months of ~~2021~~2022 compared to ~~12,597~~10,552 barrels per day in the ~~2020~~2021 period. The average sales price for U.S. NGL was $40.00 per barrel in 2022 compared to $22.41 per barrel in ~~2021 compared to $8.62 per barrel in 2020.~~2021. The average sales price for NGL in Canada was $59.23 per barrel in 2022 compared to $33.34 per barrel in ~~2021 compared to $15.04 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 ~~sales~~production volumes ~~from continuing operations~~ averaged ~~359~~361.7 million cubic feet per day (MMCFD) in the first six months of ~~2021~~2022 compared to ~~368~~358.7 MMCFD in ~~2020.~~2021. The ~~decrease~~increase of 93.0 MMCFD was primarily the result of higher volumes in Canada 12.7 MMCFD) and Eagle Ford Shale (2.7 MMCFD), partially offset by the Gulf of Mexico (12.4 MMCFD). The higher natural gas volumes in Canada was the result of lower volumes in Eagle Ford (4 MMCFD), the Gulf of Mexico (3 MMCFD) and Canada (2 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). Lower volumes in Canada and Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting the Eagle Ford Shalenew wells on production in the first ~~quarter~~half of ~~2021.~~

the year. Natural gas prices for the total Company averaged ~~$2.44~~$3.54 per thousand cubic feet (MCF) in the first six months of ~~2021,~~2022, versus ~~$1.64~~$2.44 per MCF average in the same period of ~~2020.~~2021. Average realized natural gas prices in the U.S. and Canada in the quarter were ~~$2.97~~$6.26 per MCF and ~~$2.25,~~$2.66 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.

Additional details about results of oil and natural gas operations are presented in the tables on pages 2625 and ~~27.~~26.

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

Results of Operations (contd.)

The following table ~~contains~~reports hydrocarbons produced during the three-month and six-month periods ended June 30, ~~2021~~2022 and ~~2020.~~2021.


			Three Months Ended June 30,		Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted		2021	2020	2021	2020	Barrels per day unless otherwise noted		2022	2021	2022	2021
Continuing operations

Net crude oil and condensate	Net crude oil and condensate						Net crude oil and condensate
United States	United States	Onshore	31,253	27,986	26,734	29,510	United States	Onshore	26,304	31,253	23,334	26,734
		Gulf of Mexico 1	68,468	67,002	66,427	72,866		Gulf of Mexico 1	63,427	68,468	59,363	66,427
Canada	Canada	Onshore	5,558	7,872	5,921	7,353	Canada	Onshore	4,419	5,558	4,400	5,921
		Offshore	3,689	5,852	4,137	5,495		Offshore	3,128	3,689	3,224	4,137
Other	Other		359	—	215	172	Other		1,383	359	833	215
Total net crude oil and condensate - continuing operations	Total net crude oil and condensate - continuing operations		109,327	108,712	103,434	115,396	Total net crude oil and condensate - continuing operations		98,661	109,327	91,154	103,434
Net natural gas liquids	Net natural gas liquids						Net natural gas liquids
United States	United States	Onshore	5,327	5,303	4,634	5,444	United States	Onshore	5,178	5,327	5,006	4,634
		Gulf of Mexico 1	4,763	5,219	4,721	5,944		Gulf of Mexico 1	4,913	4,763	4,223	4,721
Canada	Canada	Onshore	1,162	1,018	1,197	1,209	Canada	Onshore	859	1,162	921	1,197
Total net natural gas liquids - continuing operations	Total net natural gas liquids - continuing operations		11,252	11,540	10,552	12,597	Total net natural gas liquids - continuing operations		10,950	11,252	10,150	10,552
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	29,653	27,697	25,855	29,830	United States	Onshore	29,651	29,653	28,512	25,855
		Gulf of Mexico 1	71,962	68,717	72,308	75,333		Gulf of Mexico 1	63,703	71,962	59,902	72,308
Canada	Canada	Onshore	267,210	259,108	260,491	262,978	Canada	Onshore	288,019	267,210	273,237	260,491
Total net natural gas - continuing operations	Total net natural gas - continuing operations		368,825	355,522	358,654	368,141	Total net natural gas - continuing operations		381,373	368,825	361,651	358,654
Total net hydrocarbons - continuing operations including NCI 2,3	Total net hydrocarbons - continuing operations including NCI 2,3		182,050	179,506	173,762	189,350	Total net hydrocarbons - continuing operations including NCI 2,3		173,173	182,050	161,579	173,762
Noncontrolling interest	Noncontrolling interest						Noncontrolling interest
Net crude oil and condensate – barrels per day	Net crude oil and condensate – barrels per day		(9,800)	(10,719)	(9,489)	(11,370)	Net crude oil and condensate – barrels per day		(7,962)	(9,800)	(8,044)	(9,489)
Net natural gas liquids – barrels per day	Net natural gas liquids – barrels per day		(370)	(443)	(362)	(501)	Net natural gas liquids – barrels per day		(319)	(370)	(303)	(362)
Net natural gas – thousands of cubic feet per day			(4,024)	(4,059)	(4,091)	(4,575)
Net natural gas – thousands of cubic feet per day 2							Net natural gas – thousands of cubic feet per day 2		(3,097)	(4,024)	(2,845)	(4,091)
Total noncontrolling interest	Total noncontrolling interest		(10,841)	(11,839)	(10,533)	(12,634)	Total noncontrolling interest		(8,797)	(10,841)	(8,821)	(10,533)
Total net hydrocarbons - continuing operations excluding NCI 2,3	Total net hydrocarbons - continuing operations excluding NCI 2,3		171,209	167,667	163,229	176,716	Total net hydrocarbons - continuing operations excluding NCI 2,3		164,376	171,209	152,758	163,229

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.

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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 six-month periods ended June 30, ~~2021~~2022 and ~~2020.Comparative periods are conformed to current presentation.~~2021.


			Three Months Ended June 30,		Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
			2021	2020	2021	2020			2022		2021	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	64.55	21.42	61.60	34.59	United States	Onshore	$	110.66	64.55	$	103.39	61.60
		Gulf of Mexico 1	65.95	24.77	62.56	37.00		Gulf of Mexico 1	109.55		65.95	102.76		62.56
Canada 2	Canada 2	Onshore	60.69	16.09	56.55	26.09	Canada 2	Onshore	100.51		60.69	96.84		56.55
		Offshore	73.20	20.48	67.51	35.28		Offshore	115.65		73.20	113.46		67.51
Other	Other		—	—	—	63.51	Other		86.51		—	86.51		—
Natural gas liquids – dollars per barrel	Natural gas liquids – dollars per barrel						Natural gas liquids – dollars per barrel
United States	United States	Onshore	19.75	8.03	20.38	9.45	United States	Onshore	38.29		19.75	38.30		20.38
		Gulf of Mexico 1	24.84	7.29	24.36	7.85		Gulf of Mexico 1	40.46		24.84	41.95		24.36
Canada 2	Canada 2	Onshore	30.63	13.78	33.34	15.04	Canada 2	Onshore	63.99		30.63	59.23		33.34
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	2.54	1.62	2.84	1.74	United States	Onshore	7.06		2.54	5.89		2.84
		Gulf of Mexico 1	2.64	1.71	3.01	1.87		Gulf of Mexico 1	7.52		2.64	6.43		3.01
Canada 2	Canada 2	Onshore	2.23	1.49	2.25	1.55	Canada 2	Onshore	2.78		2.23	2.66		2.25

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 ~~$686.3~~$959.2 million for the first six months of ~~2021~~2022 compared to ~~$369.4~~$686.3 million during the same period in ~~2020.~~2021. The increased cash from operating activities of $273.0 million is primarily attributable to higher revenue from ~~sales to customers~~production ($~~465.1~~629.5 million), ~~lower lease operating expense ($80.2 million), lower~~offset by the timing of working capital settlements ($~~25.2 million)~~148.2 million; primarily higher revenue received in cash following the end of the quarter), and ~~lower general and administrative expense~~higher realized losses on derivative instruments ($~~17.3 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $156.3 million; 2020: realized gain of $150.9~~167.2 million).

Cash Required by Investing Activities

Net cash required by investing activities was ~~$193.7~~$599.3 million for the first six months of ~~2021~~2022 compared to ~~$589.2~~net cash provided by investing activities of $193.7 million during the same period in ~~2020.~~2021. In the second quarter of 2022, the Company acquired an 11.0% additional working interest in Kodiak for $46.5 million (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were ~~$463.0~~$552.8 million and ~~$589.2~~$422.8 million in the first six months of 2022 and 2021, ~~and 2020,~~ respectively. ~~These amounts include $17.7 million and $51.6 million used to fund the development~~The first quarter of 2021 included sales proceeds for the King’s Quay FPS ~~in the first six months~~ of ~~2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS~~$267.7 million, which was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company for previously incurred capital expenditures. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay..

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

Financial Condition (contd.)

Total accrual basis capital expenditures were as follows:


		Six Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2021		2020	(Millions of dollars)	2022		2021
Capital Expenditures	Capital Expenditures				Capital Expenditures
Exploration and production	Exploration and production	$	449.4	550.2	Exploration and production	$	611.4	449.4
Corporate	Corporate	8.8		7.4	Corporate	10.5		8.8
Total capital expenditures	Total capital expenditures	$	458.2	557.6	Total capital expenditures	$	621.9	458.2

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


		Six Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2021		2020	(Millions of dollars)	2022		2021
Property additions and dry hole costs per cash flow statements		$	445.3	537.6
Property additions and dry hole costs per cash flow statements 1					Property additions and dry hole costs per cash flow statements 1	$	552.8	422.8
Property additions King's Quay per cash flow statements	Property additions King's Quay per cash flow statements	17.7		51.6	Property additions King's Quay per cash flow statements	—		17.7

Acquisition of oil and gas properties 1					Acquisition of oil and gas properties 1	46.5		22.5
Geophysical and other exploration expenses	Geophysical and other exploration expenses	12.4		23.0	Geophysical and other exploration expenses	16.3		12.4
Capital expenditure accrual changes and other	Capital expenditure accrual changes and other	(17.2)		(54.6)	Capital expenditure accrual changes and other	6.3		(17.2)
Total capital expenditures	Total capital expenditures	$	458.2	557.6	Total capital expenditures	$	621.9	458.2

~~Capital~~1 Certain prior-period amounts have been reclassified to conform to the current period presentation

The increase in capital expenditures in the exploration and production business in ~~2021~~2022 compared to ~~2020 have decreased as a result~~2021 is primarily attributable to expenditures related to the Kodiak acquisition in Gulf of Mexico ($46.5 million), Cutthroat-1 exploration well in Brazil ($24.3 million), 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 ~~$386.7~~$447.5 million for the first six months of ~~2021~~2022 compared to ~~net cash provided by financing activities of $60.0~~$386.7 million during the same period in ~~2020.~~2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024 ($200.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($94.9 million), and cash dividends to shareholders of $0.325 per share ($50.5 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.25 per share, or $1.00 per share on an annualized basis. This amount represents a 43% increase from the first quarter of 2022 and a 100% increase from fourth quarter 2021. Additionally, the Company announced a capital allocation framework, approved by the Board of Directors, that allows for further capital to be returned to the shareholders beyond the current dividend, while still advancing the Company’s long-term debt reduction goals. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.

As of June 30, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,572.4 million available on its committed RCF.

In first six months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ($576.4 ~~million)~~million), early redemption cost (make whole payment) of the notes due 2022 ($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 ($75.2 million), and cash dividends to shareholders ($38.6 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).

~~As of June 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,569.0 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 ($370.0 million), offset by repayments on the revolving credit facility ($200.0 million), cash dividends to shareholders ($57.6 million), and distributions to the NCI ($32.4 million).

Working Capital

Working capital (total current assets less total current liabilities, – excluding assets and liabilities held for sale) atas of June 30, ~~2021~~2022 was a deficit of ~~$395.5~~$566.9 million, ~~$366.1~~ $268.0 million lower than December 31, ~~2020,~~2021, with the decrease ~~primarily~~primarily attributable to higher accounts payable ($~~337.0~~286.9 million), higher other accrued liabilities ($~~170.9~~122.6 million), a lower cash balance ($89.2 million) and higher operating lease liabilities ($~~63.7~~28.5 million), ~~partly~~partially offset by ~~a higher cash balance ($107.5 million) and~~ higher accounts receivable ($~~104.5~~263.9 million). Higher accounts payable is primarily due to the increase in unrealized losses on crude contracts maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 GOM acquisitions) and short-term abandonment liabilities associated with Terra Nova and Cottonwood assets. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS.

~~Capital Employed~~

At June 30, 2021, long-term debt of $2,762.9 million had decreased by $225.2 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 ($576.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.

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

Financial Condition (contd.)

payable is primarily due to the increase in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the remainder of 2022 as well as higher trade payables principally related to the Khaleesi, Mormont and Samurai field development project. Higher other accrued liabilities are associated with higher contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project. Higher accounts receivable are principally due to higher crude oil pricing.

Capital Employed

At June 30, 2022, long-term debt of $2,267.9 million had decreased by $197.5 million compared to December 31, 2021, primarily as a result of the partial redemption of notes due 2024 ($200.0 million). The total of the fixed-rate notes had a weighted average maturity of 7.4 years and a weighted average coupon of 6.2%.

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


		June 30, 2021				December 31, 2020					June 30, 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	$	2,762.9	41.6	%	$	2,988.1	41.5	%	Long-term debt	$	2,267.9	34.5	%	$	2,465.4	37.2	%
Murphy shareholders' equity	Murphy shareholders' equity	3,880.6		58.4	%	4,214.3		58.5	%	Murphy shareholders' equity	4,312.8		65.5	%	4,157.3		62.8	%
Total capital employed	Total capital employed	$	6,643.5	100.0	%	$	7,202.4	100.0	%	Total capital employed	$	6,580.7	100.0	%	$	6,622.7	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. AtAs of June 30, ~~2021,~~2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$121.9~~$82.7 million in ~~Canada~~Canada. In addition, approximately $21.8 million of cash was held in Brunei, $17.7 million of cash was held in Mexico and ~~$8.4~~$13.6 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,~~22, several factors have continued to contribute to the higher average crude oil ~~prices continued to recover~~price during the second quarter, ~~of 2021 versus~~which directly impacts the ~~second quarter of 2020~~Company’s product revenue from sales (Q2 ~~2020 WTI: $27.85;~~2022; $108.41 Q1 2022; $94.29; Q2 ~~2021 WTI:~~2021: $66.07). Currently, recessionary concerns have placed some downward pressure on average crude oil prices. As of close on August ~~3, 2021,~~2, 2022, the NYMEX WTI forward curve price for the remainder of ~~2021~~2022 and ~~2022~~2023 were ~~$69.71~~lower at $92.82 and ~~$65.34~~$86.14 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and ~~OPEC+ decisions)~~production sector investment, inflation 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 third quarter, production is expected to average between ~~162~~180.0 and ~~170~~188.0 MBOEPD, excluding ~~NCI.~~noncontrolling interest (NCI).

The Company’s capital expenditure spend for ~~2021~~2022 is expected to be between ~~$685.0~~$900.0 million and ~~$715.0 million.~~$950.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures and other expenditures ~~will be~~are routinely reviewed ~~during 2021~~ 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. ~~In the third quarter of 2021, the Company announced the redemption of $150.0 million in aggregate principal amount of its 6.875% notes due 2024.~~

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~~

Table of the COVID-19 pandemic and is encouraged by the progress and acceptance of the vaccinations which has positively impacted current and expected future energy demand for the next year compared to one year ago.Contents

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

As of August ~~3, 2021,~~2, 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

7/1/2021

12/31/2021

United States

WTI²

Fixed price derivative swap

20,000

$44.88

7/1/2022

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

Area

Commodity

Type

Start Date

End Date

United States

WTI²

Derivative collars

25,000

$63.24

$75.20

7/1/2022

12/31/2022

1 West Texas Intermediate

~~Table of Contents~~

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

Volumes
(MMcf/d)

Price
(CAD/Mcf)Price/Mcf

Remaining Period

Area

Commodity

Type

Start Date

End Date

~~Montney~~Canada

Natural Gas

Fixed price forward sales ~~at AECO~~

~~241~~247

C$~~2.57~~2.34

7/1/~~2021~~2022

~~12/~~10/31/~~2021~~2022

~~Montney~~Canada

Natural Gas

Fixed price forward sales ~~at AECO~~

~~231~~266

C$~~2.42~~

~~1/1/2022~~

~~1/31/2022~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales at AECO~~

~~221~~

~~C$2.41~~

~~2/1/2022~~

~~4/30/2022~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales at AECO~~

~~250~~

~~C$2.40~~

~~5/1/2022~~

~~5/31/2022~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales at AECO~~

~~292~~

~~C$2.39~~

~~6/1/2022~~

~~10/31/2022~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales at AECO~~

~~311~~

~~C$2.40~~2.36

11/1/2022

12/31/2022

~~Montney~~Canada

Natural Gas

Fixed price forward sales ~~at AECO~~

~~294~~269

C$~~2.38~~2.36

1/1/2023

3/31/2023

~~Montney~~Canada

Natural Gas

Fixed price forward sales ~~at AECO~~

~~275~~250

C$~~2.37~~2.35

4/1/2023

12/31/2023

~~Montney~~Canada

Natural Gas

Fixed price forward sales ~~at AECO~~

~~185~~162

C$~~2.41~~2.39

1/1/2024

12/31/2024

Canada

Natural Gas

Fixed price forward sales

US$2.05

7/1/2022

12/31/2022

Canada

Natural Gas

Fixed price forward sales

US$1.98

1/1/2023

10/31/2024

Canada

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”, “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 3736 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There were commodity transactions in place at June 30, ~~2021,~~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 ~~$106.9~~$78.5 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 June 30, ~~2021.~~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 June 30, ~~2021,~~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.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in 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 3938 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

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SIGNATURE

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


			MURPHY OIL CORPORATION
			(Registrant)

			By			/s/ ~~CHRISTOPHER~~PAUL D. ~~HULSE~~VAUGHAN
						~~Christopher~~Paul D. ~~Hulse~~Vaughan
						Vice President and Controller
						(Chief Accounting Officer and Duly Authorized Officer)

August ~~5, 2021~~4, 2022

(Date)

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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.

~~Incorporated by Reference to the Indicated Filing by Murphy Oil Corporation~~

~~10.26~~

~~Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors~~

~~Exhibit A to definitive proxy statement filed March 26, 2021~~

*10.27

~~Form of non-employee director restricted stock unit award – stock settled grant agreement (2021 NED Plan)~~

*31.1

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32

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

3938


	Total Assets at June 30, 2021		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States	$	6,868.2	648.9	194.7	228.3	(143.1)
Canada	2,366.7		120.6	12.7	59.2	(19.5)
Other	270.4		0	(10.4)	0	(9.0)
Total exploration and production	9,505.3		769.5	197.0	287.5	(171.6)
Corporate	1,097.7		(219.9)	(223.9)	(76.0)	(151.6)
Continuing operations	10,603.0		549.6	(26.9)	211.5	(323.2)
Discontinued operations, net of tax	1.2		0	(0.1)	0	(1.2)
Total	$	10,604.2	549.6	(27.0)	211.5	(324.4)

			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States			1,139.2	313.7	739.8	(839.1)
Canada			224.6	(111.6)	148.9	(26.4)
Other			0	(17.3)	1.8	(61.3)
Total exploration and production			1,363.8	184.8	890.5	(926.8)
Corporate			(434.2)	(478.8)	324.8	99.8
Continuing operations			929.6	(294.0)	1,215.3	(827.0)
Discontinued operations, net of tax			0	0.1	0	(6.1)
Total			929.6	(293.9)	1,215.3	(833.1)


(Thousands of dollars)	Operating Leases		Finance Leases	Total
2021	$	109,284	534	109,818
2022	185,790		1,068	186,858
2023	138,692		1,069	139,761
2024	133,502		1,069	134,571
2025	83,210		1,069	84,279
Remaining	726,103		3,472	729,575
Total future minimum lease payments	1,376,581		8,281	1,384,862
Less imputed interest	(382,394)		(1,403)	(383,797)
Present value of lease liabilities 1	$	994,187	6,878	1,001,065