UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, ~~2020~~2021


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

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


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

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


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

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at October 31, ~~2020~~2021 was ~~153,598,625~~154,459,128.

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			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			1514
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			1819
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			2120
~~Note P – Acquisitions~~			22
~~Note Q – Restructuring Charges~~			22

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




Item 3. Quantitative and Qualitative Disclosures About Market Risk			3735
Item 4. Controls and Procedures			3735
Part II – Other Information			3836
Item 1. Legal Proceedings			3836
Item 1A. Risk Factors			3836
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			36
Item 6. Exhibits			4036
Signature			4137

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)


(Thousands of dollars)	(Thousands of dollars)	September 30, 2020		December 31, 2019	(Thousands of dollars)	September 30, 2021		December 31, 2020
ASSETS	ASSETS				ASSETS
Current assets	Current assets				Current assets
Cash and cash equivalents	Cash and cash equivalents	$	219,636	306,760	Cash and cash equivalents	$	505,067	310,606
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019		279,149		426,684
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020					Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020	186,683		262,014
Inventories	Inventories	67,856		76,123	Inventories	57,411		66,076
Prepaid expenses	Prepaid expenses	58,099		40,896	Prepaid expenses	40,583		33,860
Assets held for sale	Assets held for sale	108,916		123,864	Assets held for sale	40,987		327,736
Total current assets	Total current assets	733,656		974,327	Total current assets	830,731		1,000,292
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,102,285 in 2020 and $9,333,646 in 2019		8,592,834		9,969,743
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020					Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020	8,112,093		8,269,038
Operating lease assets	Operating lease assets	765,484		598,293	Operating lease assets	918,719		927,658
Deferred income taxes	Deferred income taxes	347,053		129,287	Deferred income taxes	442,212		395,253
Deferred charges and other assets	Deferred charges and other assets	30,324		46,854	Deferred charges and other assets	27,101		28,611

Total assets	Total assets	$	10,469,351	11,718,504	Total assets	$	10,330,856	10,620,852
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY				LIABILITIES AND EQUITY
Current liabilities	Current liabilities				Current liabilities

Current maturities of long-term debt, finance lease					Current maturities of long-term debt, finance lease	$	646	—
Accounts payable	Accounts payable	$	295,398	602,096	Accounts payable	615,436		407,097
Income taxes payable	Income taxes payable	17,813		19,049	Income taxes payable	18,035		18,018
Other taxes payable	Other taxes payable	23,755		18,613	Other taxes payable	26,997		22,498
Operating lease liabilities	Operating lease liabilities	100,169		92,286	Operating lease liabilities	157,294		103,758
Other accrued liabilities	Other accrued liabilities	157,574		197,447	Other accrued liabilities	316,205		150,578
Liabilities associated with assets held for sale	Liabilities associated with assets held for sale	14,677		13,298	Liabilities associated with assets held for sale	—		14,372
Total current liabilities	Total current liabilities	609,386		942,789	Total current liabilities	1,134,613		716,321
Long-term debt, including capital lease obligation		2,987,057		2,803,381
Long-term debt, including finance lease obligation					Long-term debt, including finance lease obligation	2,613,703		2,988,067
Asset retirement obligations	Asset retirement obligations	856,856		825,794	Asset retirement obligations	797,627		816,308
Deferred credits and other liabilities	Deferred credits and other liabilities	635,980		613,407	Deferred credits and other liabilities	723,732		680,580
Non-current operating lease liabilities	Non-current operating lease liabilities	686,516		521,324	Non-current operating lease liabilities	781,114		845,088
Deferred income taxes	Deferred income taxes	179,511		207,198	Deferred income taxes	166,120		180,341

Total liabilities	Total liabilities	5,955,306		5,913,893	Total liabilities	6,216,909		6,226,705
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 2020 and 195,089,269 shares in 2019		195,101		195,089
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued					Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2021 and 195,100,628 shares in 2020					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
Capital in excess of par value	Capital in excess of par value	936,318		949,445	Capital in excess of par value	921,227		941,692
Retained earnings	Retained earnings	5,560,673		6,614,304	Retained earnings	5,069,578		5,369,538
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(657,995)		(574,161)	Accumulated other comprehensive loss	(580,174)		(601,333)
Treasury stock	Treasury stock	(1,690,661)		(1,717,217)	Treasury stock	(1,656,224)		(1,690,661)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	4,343,436		5,467,460	Murphy Shareholders' Equity	3,949,508		4,214,337
Noncontrolling interest	Noncontrolling interest	170,609		337,151	Noncontrolling interest	164,439		179,810
Total equity	Total equity	4,514,045		5,804,611	Total equity	4,113,947		4,394,147
Total liabilities and equity	Total liabilities and equity	$	10,469,351	11,718,504	Total liabilities and equity	$	10,330,856	10,620,852

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars, except per share amounts)	(Thousands of dollars, except per share amounts)	2020		2019	2020	2019	(Thousands of dollars, except per share amounts)	2021		2020	2021		2020
Revenues and other income	Revenues and other income						Revenues and other income
Revenue from sales to customers	Revenue from sales to customers	$	425,324	750,337	1,311,627	2,060,127	Revenue from sales to customers	$	687,549	425,324	$	2,038,905	1,311,627
(Loss) gain on crude contracts		(5,290)		63,247	319,502	121,163
(Loss) gain on derivative instruments							(Loss) gain on derivative instruments	(59,164)		(5,290)	(499,794)		319,502
Gain on sale of assets and other income	Gain on sale of assets and other income	1,831		3,493	6,006	10,283	Gain on sale of assets and other income	2,315		1,831	21,217		6,006
Total revenues and other income	Total revenues and other income	421,865		817,077	1,637,135	2,191,573	Total revenues and other income	630,700		421,865	1,560,328		1,637,135
Costs and expenses	Costs and expenses						Costs and expenses
Lease operating expenses	Lease operating expenses	124,491		147,632	478,283	416,460	Lease operating expenses	130,131		124,491	403,708		478,283
Severance and ad valorem taxes	Severance and ad valorem taxes	6,781		13,803	22,645	36,972	Severance and ad valorem taxes	11,670		6,781	32,215		22,645
Transportation, gathering and processing	Transportation, gathering and processing	41,322		54,305	126,779	128,748	Transportation, gathering and processing	44,588		41,322	137,196		126,779
Exploration expenses, including undeveloped lease amortization	Exploration expenses, including undeveloped lease amortization	12,092		12,358	61,686	75,570	Exploration expenses, including undeveloped lease amortization	24,517		12,092	49,840		61,686
Selling and general expenses	Selling and general expenses	28,509		55,366	104,381	176,258	Selling and general expenses	27,210		28,509	85,826		104,381
Restructuring expenses	Restructuring expenses	4,982		0	46,379	0	Restructuring expenses	—		4,982	—		46,379
Depreciation, depletion and amortization	Depreciation, depletion and amortization	231,603		325,562	769,151	819,270	Depreciation, depletion and amortization	189,806		231,603	615,372		769,151
Accretion of asset retirement obligations	Accretion of asset retirement obligations	10,778		10,587	31,213	29,824	Accretion of asset retirement obligations	12,198		10,778	34,854		31,213
Impairment of assets	Impairment of assets	219,138		0	1,206,284	0	Impairment of assets	—		219,138	171,296		1,206,284
Other (benefit) expense	Other (benefit) expense	20,224		(29,000)	(2,957)	26,442	Other (benefit) expense	(32,791)		20,224	58,616		(2,957)
Total costs and expenses	Total costs and expenses	699,920		590,613	2,843,844	1,709,544	Total costs and expenses	407,329		699,920	1,588,923		2,843,844
Operating (loss) income from continuing operations		(278,055)		226,464	(1,206,709)	482,029
Other (loss)
Interest and other (loss)		(5,177)		(4,418)	(10,107)	(18,134)
Operating income (loss) from continuing operations							Operating income (loss) from continuing operations	223,371		(278,055)	(28,595)		(1,206,709)
Other income (loss)							Other income (loss)
Interest income and other (loss)							Interest income and other (loss)	(1,593)		(5,177)	(11,459)		(10,107)
Interest expense, net	Interest expense, net	(45,182)		(44,930)	(124,877)	(145,095)	Interest expense, net	(46,925)		(45,182)	(178,399)		(124,877)
Total other (loss)		(50,359)		(49,348)	(134,984)	(163,229)
(Loss) income from continuing operations before income taxes		(328,414)		177,116	(1,341,693)	318,800
Income tax (benefit) expense		(62,584)		18,782	(248,890)	38,719
(Loss) income from continuing operations		(265,830)		158,334	(1,092,803)	280,081
(Loss) income from discontinued operations, net of income taxes		(778)		953,368	(6,907)	1,027,632
Net (loss) income including noncontrolling interest		(266,608)		1,111,702	(1,099,710)	1,307,713
Less: Net (loss) income attributable to noncontrolling interest		(23,055)		22,700	(122,869)	86,257
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY		$	(243,553)	1,089,002	(976,841)	1,221,456
(LOSS) INCOME PER COMMON SHARE – BASIC
Total other loss							Total other loss	(48,518)		(50,359)	(189,858)		(134,984)
Income (loss) from continuing operations before income taxes							Income (loss) from continuing operations before income taxes	174,853		(328,414)	(218,453)		(1,341,693)
Income tax expense (benefit)							Income tax expense (benefit)	36,838		(62,584)	(62,498)		(248,890)
Income (loss) from continuing operations							Income (loss) from continuing operations	138,015		(265,830)	(155,955)		(1,092,803)
(Loss) from discontinued operations, net of income taxes							(Loss) from discontinued operations, net of income taxes	(706)		(778)	(600)		(6,907)
Net income (loss) including noncontrolling interest							Net income (loss) including noncontrolling interest	137,309		(266,608)	(156,555)		(1,099,710)
Less: Net income (loss) attributable to noncontrolling interest							Less: Net income (loss) attributable to noncontrolling interest	28,853		(23,055)	85,509		(122,869)
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY							NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	108,456	(243,553)	$	(242,064)	(976,841)
INCOME (LOSS) PER COMMON SHARE – BASIC							INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	Continuing operations	$	(1.58)	0.85	(6.31)	1.16	Continuing operations	$	0.70	(1.58)	$	(1.57)	(6.31)
Discontinued operations	Discontinued operations	(0.01)		5.94	(0.05)	6.14	Discontinued operations	—		(0.01)	—		(0.05)
Net (loss) income		$	(1.59)	6.79	(6.36)	7.30
(LOSS) INCOME PER COMMON SHARE – DILUTED
Net income (loss)							Net income (loss)	$	0.70	(1.59)	$	(1.57)	(6.36)
INCOME (LOSS) PER COMMON SHARE – DILUTED							INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	Continuing operations	$	(1.58)	0.84	(6.31)	1.16	Continuing operations	$	0.70	(1.58)	$	(1.57)	(6.31)
Discontinued operations	Discontinued operations	(0.01)		5.92	(0.05)	6.11	Discontinued operations	—		(0.01)	—		(0.05)
Net (loss) income		$	(1.59)	6.76	(6.36)	7.27
Net income (loss)							Net income (loss)	$	0.70	(1.59)	$	(1.57)	(6.36)
Cash dividends per Common share	Cash dividends per Common share	0.125		0.25	0.50	0.75	Cash dividends per Common share	$	0.125	0.125	0.375		0.500

Average Common shares outstanding (thousands)	Average Common shares outstanding (thousands)						Average Common shares outstanding (thousands)
Basic	Basic	153,596		160,366	153,480	167,310	Basic	154,439		153,596	154,239		153,480
Diluted	Diluted	153,596		160,980	153,480	168,105	Diluted	155,932		153,596	154,239		153,480

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
Net (loss) income including noncontrolling interest		$	(266,608)	1,111,702	(1,099,710)	1,307,713
Net income (loss) including noncontrolling interest							Net income (loss) including noncontrolling interest	$	137,309	(266,608)	$	(156,555)	(1,099,710)
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	28,323		(17,128)	(39,520)	36,927	Net (loss) gain from foreign currency translation	(31,308)		28,323	6,534		(39,520)
Retirement and postretirement benefit plans	Retirement and postretirement benefit plans	3,726		2,761	(45,219)	8,277	Retirement and postretirement benefit plans	4,653		3,726	12,935		(45,219)
Deferred loss on interest rate hedges reclassified to interest expense	Deferred loss on interest rate hedges reclassified to interest expense	297		585	905	1,756	Deferred loss on interest rate hedges reclassified to interest expense	—		297	1,690		905

Other comprehensive (loss) income	Other comprehensive (loss) income	32,346		(13,782)	(83,834)	46,960	Other comprehensive (loss) income	(26,655)		32,346	21,159		(83,834)
COMPREHENSIVE (LOSS) INCOME		$	(234,262)	1,097,920	(1,183,544)	1,354,673
COMPREHENSIVE INCOME (LOSS)							COMPREHENSIVE INCOME (LOSS)	$	110,654	(234,262)	$	(135,396)	(1,183,544)

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


		Nine Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Operating Activities	Operating Activities				Operating Activities
Net (loss) income including noncontrolling interest		$	(1,099,710)	1,307,713
Adjustments to reconcile net (loss) income to net cash provided by continuing operations activities:
Loss (income) from discontinued operations		6,907		(1,027,632)
Net income (loss) including noncontrolling interest					Net income (loss) including noncontrolling interest	$	(156,555)	(1,099,710)
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities					Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities
Loss from discontinued operations					Loss from discontinued operations	600		6,907
Depreciation, depletion and amortization	Depreciation, depletion and amortization	769,151		819,270	Depreciation, depletion and amortization	615,372		769,151
Previously suspended exploration costs		8,255		12,901
Dry hole and previously suspended exploration costs					Dry hole and previously suspended exploration costs	17,899		8,255
Amortization of undeveloped leases	Amortization of undeveloped leases	21,951		21,680	Amortization of undeveloped leases	13,872		21,951
Accretion of asset retirement obligations	Accretion of asset retirement obligations	31,213		29,824	Accretion of asset retirement obligations	34,854		31,213
Impairment of assets	Impairment of assets	1,206,284		0	Impairment of assets	171,296		1,206,284
Noncash restructuring expense	Noncash restructuring expense	17,565		0	Noncash restructuring expense	—		17,565
Deferred income tax (benefit) expense	Deferred income tax (benefit) expense	(231,748)		50,597	Deferred income tax (benefit) expense	(65,149)		(231,748)

Mark to market (gain) loss on contingent consideration		(29,476)		512
Mark to market (gain) loss on crude contracts		(104,463)		(100,076)
Mark to market loss (gain) on contingent consideration					Mark to market loss (gain) on contingent consideration	105,111		(29,476)
Mark to market loss (gain) on derivative instruments					Mark to market loss (gain) on derivative instruments	228,497		(104,463)
Long-term non-cash compensation	Long-term non-cash compensation	35,200		60,567	Long-term non-cash compensation	42,080		35,200
Net decrease (increase) in noncash operating working capital		(26,261)		40,257
Net decrease (increase) in noncash working capital					Net decrease (increase) in noncash working capital	117,330		(26,261)
Other operating activities, net	Other operating activities, net	(26,837)		(62,386)	Other operating activities, net	(33,924)		(26,837)
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	578,031		1,153,227	Net cash provided by continuing operations activities	1,091,283		578,031
Investing Activities	Investing Activities				Investing Activities
Property additions and dry hole costs	Property additions and dry hole costs	(648,725)		(995,509)	Property additions and dry hole costs	(564,230)		(648,725)
Property additions for King's Quay FPS	Property additions for King's Quay FPS	(74,936)		(13,637)	Property additions for King's Quay FPS	(17,734)		(74,936)
Acquisition of oil and gas properties		0		(1,212,949)

Proceeds from sales of property, plant and equipment	Proceeds from sales of property, plant and equipment	0		19,072	Proceeds from sales of property, plant and equipment	270,038		—
Net cash required by investing activities	Net cash required by investing activities	(723,661)		(2,203,023)	Net cash required by investing activities	(311,926)		(723,661)
Financing Activities	Financing Activities				Financing Activities
Borrowings on revolving credit facility	Borrowings on revolving credit facility	450,000		1,575,000	Borrowings on revolving credit facility	165,000		450,000
Repayment of revolving credit facility	Repayment of revolving credit facility	(250,000)		(1,900,000)	Repayment of revolving credit facility	(365,000)		(250,000)
Retirement of debt					Retirement of debt	(726,358)		(12,225)
Debt issuance, net of cost					Debt issuance, net of cost	541,913		(613)
Early redemption of debt cost					Early redemption of debt cost	(36,756)		—
Distributions to noncontrolling interest					Distributions to noncontrolling interest	(100,880)		(43,673)
Cash dividends paid	Cash dividends paid	(76,790)		(125,437)	Cash dividends paid	(57,896)		(76,790)
Distributions to noncontrolling interest		(43,673)		(97,510)
Early retirement of debt		(12,225)		0
Withholding tax on stock-based incentive awards	Withholding tax on stock-based incentive awards	(7,094)		(6,991)	Withholding tax on stock-based incentive awards	(4,973)		(7,094)
Debt issuance, net of cost		(613)		0

Capital lease obligation payments	Capital lease obligation payments	(514)		(510)	Capital lease obligation payments	(643)		(514)
Repurchase of common stock		0		(405,938)

Net cash (required) provided by financing activities	Net cash (required) provided by financing activities	59,091		(961,386)	Net cash (required) provided by financing activities	(585,593)		59,091
Cash Flows from Discontinued Operations 1	Cash Flows from Discontinued Operations 1				Cash Flows from Discontinued Operations 1
Operating activities	Operating activities	(1,202)		74,361	Operating activities	—		(1,202)
Investing activities	Investing activities	4,494		1,985,202	Investing activities	—		4,494
Financing activities	Financing activities	0		(4,914)	Financing activities	—		—
Net cash provided by discontinued operations	Net cash provided by discontinued operations	3,292		2,054,649	Net cash provided by discontinued operations	—		3,292
Cash transferred from discontinued operations to continuing operations		0		2,083,565

Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	(585)		2,593	Effect of exchange rate changes on cash and cash equivalents	697		(585)
Net increase (decrease) in cash and cash equivalents	Net increase (decrease) in cash and cash equivalents	(87,124)		74,976	Net increase (decrease) in cash and cash equivalents	194,461		(87,124)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period	306,760		359,923	Cash and cash equivalents at beginning of period	310,606		306,760
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	219,636	434,899	Cash and cash equivalents at end of period	$	505,067	219,636

1 Net cash provided by discontinued operations is not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
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 September 30, 2020 and 195,083,364 shares at September 30, 2019
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued							Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	—	—	$	—	—
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2021 and 195,100,628 shares at September 30, 2020							Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2021 and 195,100,628 shares at September 30, 2020
Balance at beginning of period	Balance at beginning of period	195,101		195,083	195,089	195,077	Balance at beginning of period	195,101		195,101	195,101		195,089
Exercise of stock options	Exercise of stock options	—		—	12	6	Exercise of stock options	—		—	—		12
Balance at end of period	Balance at end of period	195,101		195,083	195,101	195,083	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	931,429		933,944	949,445	979,642	Balance at beginning of period	915,181		931,429	941,692		949,445
Exercise of stock options, including income tax benefits	Exercise of stock options, including income tax benefits	—		—	(156)	(123)	Exercise of stock options, including income tax benefits	(35)		—	(661)		(156)
Restricted stock transactions and other	Restricted stock transactions and other	(409)		—	(33,649)	(38,732)	Restricted stock transactions and other	(402)		(409)	(38,749)		(33,649)
Share-based compensation	Share-based compensation	5,298		7,365	20,678	25,041	Share-based compensation	6,483		5,298	18,945		20,678
Adjustments to acquisition valuation		—		—	—	(24,519)

Balance at end of period	Balance at end of period	936,318		941,309	936,318	941,309	Balance at end of period	921,227		936,318	921,227		936,318
Retained Earnings	Retained Earnings						Retained Earnings
Balance at beginning of period	Balance at beginning of period	5,823,426		5,677,248	6,614,304	5,513,529	Balance at beginning of period	4,980,428		5,823,426	5,369,538		6,614,304
Net (loss) income for the period		(243,553)		1,089,002	(976,841)	1,221,456
Net (loss) attributable to Murphy							Net (loss) attributable to Murphy	108,456		(243,553)	(242,064)		(976,841)

Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact		—		—	—	116,768

Cash dividends	Cash dividends	(19,200)		(39,934)	(76,790)	(125,437)	Cash dividends	(19,306)		(19,200)	(57,896)		(76,790)
Balance at end of period	Balance at end of period	5,560,673		6,726,316	5,560,673	6,726,316	Balance at end of period	5,069,578		5,560,673	5,069,578		5,560,673
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss						Accumulated Other Comprehensive Loss
Balance at beginning of period	Balance at beginning of period	(690,341)		(549,045)	(574,161)	(609,787)	Balance at beginning of period	(553,519)		(690,341)	(601,333)		(574,161)
Foreign currency translation (loss) gain, net of income taxes		28,323		(17,128)	(39,520)	36,927
Foreign currency translation gain (loss), net of income taxes							Foreign currency translation gain (loss), net of income taxes	(31,308)		28,323	6,534		(39,520)
Retirement and postretirement benefit plans, net of income taxes	Retirement and postretirement benefit plans, net of income taxes	3,726		2,761	(45,219)	8,277	Retirement and postretirement benefit plans, net of income taxes	4,653		3,726	12,935		(45,219)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	297		585	905	1,756	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	—		297	1,690		905

Balance at end of period	Balance at end of period	(657,995)		(562,827)	(657,995)	(562,827)	Balance at end of period	(580,174)		(657,995)	(580,174)		(657,995)
Treasury Stock	Treasury Stock						Treasury Stock
Balance at beginning of period	Balance at beginning of period	(1,691,070)		(1,517,217)	(1,717,217)	(1,249,162)	Balance at beginning of period	(1,656,591)		(1,691,070)	(1,690,661)		(1,717,217)
Purchase of treasury shares		—		(106,014)	—	(405,938)

Awarded restricted stock, net of forfeitures	Awarded restricted stock, net of forfeitures	409		—	26,556	31,869	Awarded restricted stock, net of forfeitures	343		409	33,888		26,556
Balance at end of period – 41,502,003 shares of Common Stock in 2020 and 37,853,330 shares of Common Stock in 2019, at cost		(1,690,661)		(1,623,231)	(1,690,661)	(1,623,231)
Exercise of stock options							Exercise of stock options	24		—	549		—
Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost							Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost	(1,656,224)		(1,690,661)	(1,656,224)		(1,690,661)
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	4,343,436		5,676,650	4,343,436	5,676,650	Murphy Shareholders’ Equity	3,949,508		4,343,436	3,949,508		4,343,436
Noncontrolling Interest	Noncontrolling Interest						Noncontrolling Interest
Balance at beginning of period	Balance at beginning of period	204,937		358,532	337,151	368,343	Balance at beginning of period	161,228		204,937	179,810		337,151
Acquisition closing adjustments		—		(3,328)	—	(7,920)
Net (loss) income attributable to noncontrolling interest		(23,055)		22,700	(122,869)	86,257

Net income (loss) attributable to noncontrolling interest							Net income (loss) attributable to noncontrolling interest	28,853		(23,055)	85,509		(122,869)
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(11,273)		(28,734)	(43,673)	(97,510)	Distributions to noncontrolling interest owners	(25,642)		(11,273)	(100,880)		(43,673)
Balance at end of period	Balance at end of period	170,609		349,170	170,609	349,170	Balance at end of period	164,439		170,609	164,439		170,609
Total Equity	Total Equity	$	4,514,045	6,025,820	4,514,045	6,025,820	Total Equity	$	4,113,947	4,514,045	$	4,113,947	4,514,045

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/~~the~~ Company) 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, ~~further discussed in Note P – Acquisitions,~~ we hold a 0.5% interest in 2 variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, ~~2020,~~2021, our maximum exposure to loss was ~~$3.5~~$3.4 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 September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, ~~2020~~2021 and ~~2019,~~2020, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

~~Financial~~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 ~~2019~~2020 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, ~~2020~~2021 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

~~Financial Instruments– Credit Losses.~~ In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.

~~Fair Value Measurement.~~ In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.

~~Recent Accounting Pronouncements~~

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. ~~Early adoption is permitted.~~ The Company ~~is currently assessing~~adopted this guidance in the ~~potential~~first quarter of 2021 and it did not have a material impact ~~of this ASU to~~on its consolidated financial statements.

~~Compensation-Retirement Benefits-Defined Benefit Plans-General.~~ ~~In August 2018,~~Recent Accounting Pronouncements

None affecting the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years ending after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.Company.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into 2 key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from 3 primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

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

U.S. - In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada - In Canada, contracts ~~are primarily~~include long-term floating commodity index priced ~~except for certain~~and natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Disaggregation of Revenue

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

For the three-month and nine-month periods ended September 30, ~~2020,~~2021, the Company recognized ~~$425.3~~$687.5 million and ~~$1,311.6~~$2,038.9 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and nine-month periods ended September 30, ~~2019,~~2020, the Company recognized ~~$750.3~~$425.3 million and ~~$2,060.1~~$1,311.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.


			Three Months Ended September 30,			Nine Months Ended September 30,				Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)		2020		2019	2020	2019	(Thousands of dollars)		2021		2020	2021	2020
Net crude oil and condensate revenue	Net crude oil and condensate revenue							Net crude oil and condensate revenue
United States	United States	Onshore	$	86,498	219,515	272,284	547,756	United States	Onshore	$	167,010	86,498	464,767	272,284
		Offshore	216,918		398,518	714,143	1,090,462		Offshore	340,001		216,918	1,079,418	714,143
Canada	Canada	Onshore	32,358		31,758	67,268	88,730	Canada	Onshore	29,110		32,358	89,708	67,268
		Offshore	19,173		28,407	54,864	115,686		Offshore	20,499		19,173	70,333	54,864
Other	Other		0		1,933	1,806	7,908	Other		—		—	—	1,806
Total crude oil and condensate revenue	Total crude oil and condensate revenue		354,947		680,131	1,110,365	1,850,542	Total crude oil and condensate revenue		556,620		354,947	1,704,226	1,110,365

Net natural gas liquids revenue	Net natural gas liquids revenue							Net natural gas liquids revenue
United States	United States	Onshore	6,766		5,557	16,145	22,497	United States	Onshore	16,356		6,766	33,480	16,145
		Offshore	4,765		8,414	13,255	18,184		Offshore	11,046		4,765	31,866	13,255
Canada	Canada	Onshore	2,780		2,751	6,090	8,987	Canada	Onshore	4,501		2,780	11,728	6,090
Total natural gas liquids revenue	Total natural gas liquids revenue		14,311		16,722	35,490	49,668	Total natural gas liquids revenue		31,903		14,311	77,074	35,490

Net natural gas revenue	Net natural gas revenue							Net natural gas revenue
United States	United States	Onshore	4,529		5,848	14,177	20,762	United States	Onshore	11,127		4,529	24,442	14,177
		Offshore	9,827		15,879	35,487	29,575		Offshore	17,444		9,827	56,855	35,487
Canada	Canada	Onshore	41,710		31,757	116,108	109,580	Canada	Onshore	70,455		41,710	176,308	116,108
Total natural gas revenue	Total natural gas revenue		56,066		53,484	165,772	159,917	Total natural gas revenue		99,026		56,066	257,605	165,772
Total revenue from contracts with customers	Total revenue from contracts with customers		425,324		750,337	1,311,627	2,060,127	Total revenue from contracts with customers		687,549		425,324	2,038,905	1,311,627

(Loss) gain on crude contracts			(5,290)		63,247	319,502	121,163
(Loss) gain on derivative instruments								(Loss) gain on derivative instruments		(59,164)		(5,290)	(499,794)	319,502
Gain on sale of assets and other income	Gain on sale of assets and other income		1,831		3,493	6,006	10,283	Gain on sale of assets and other income		2,315		1,831	21,217	6,006
Total revenue and other income	Total revenue and other income		$	421,865	817,077	1,637,135	2,191,573	Total revenue and other income		$	630,700	421,865	1,560,328	1,637,135

Contract Balances and Asset Recognition

As of September 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were ~~$70.8~~$144.0 million and ~~$186.8~~$135.2 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, ~~(see Note B),~~ the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any ~~upstream oil and gas sale~~revenue contracts that have financing components as ofat September 30, ~~2020.~~2021.

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Performance Obligations

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

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

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

As of September 30, ~~2020,~~2021, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:

໿

Current Long-Term Contracts Outstanding at September 30, ~~2020~~

~~Approximate Volumes~~2021

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Oil

Q4 2021

Fixed quantity delivery in Eagle Ford

17,000 BOED

U.S.

Natural Gas and NGL

Q1 2023

Deliveries from dedicated acreage in Eagle Ford

As produced

Canada

Natural Gas

Q4 ~~2020~~

~~Contracts to sell natural gas at Alberta AECO fixed prices~~

~~59 MMCFD~~

~~Canada~~

~~Natural Gas~~

~~Q4 2020~~

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

~~60 MMCFD~~

~~Canada~~

~~Natural Gas~~

Q4 2021

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

10 MMCFD

Canada

Natural Gas

Q4 2022

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

8 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at CAD fixed prices

205 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD ~~Index~~fixed pricing

3520 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~~index pricing

3031 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~~index pricing

49 MMCFD

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.

AtAs of September 30, ~~2020,~~2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of ~~$187.9~~$186.6 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~

(Thousands of dollars) 2020 2019
Beginning balance at January 1 $ 217,326 207,855
Additions pending the determination of proved reserves 9,941 86,025
Capitalized exploratory well costs charged to expense (39,408) (13,145)
Balance at September 30 $ 187,859 280,735

The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below). The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017.2020.

Table of Contents

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	5,007		9,941

Capitalized exploratory well costs charged to expense	—		(39,408)
Balance at September 30	$	186,623	187,859

The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below).

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


		September 30,								September 30,
		2020				2019				2021				2020

(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	$	8,000	1	0	64,711	5	5	Zero to one year	$	3,297	2	2	8,000	1	—
One to two years	One to two years	54,334		5	5	63,615	1	1	One to two years	—		—	—	54,334	5	5
Two to three years	Two to three years	0		0	0	27,500	1	0	Two to three years	53,078		5	5	—	—	—
Three years or more	Three years or more	125,525		6	0	124,909	5	0	Three years or more	130,248		6	—	125,525	6	—
		$	187,859	12	5	280,735	12	6		$	186,623	13	7	187,859	12	5

Of the ~~$179.9~~$183.3 million of exploratory well costs capitalized more than one year at September 30, ~~2020, $88.2~~2021, $92.3 million is in Vietnam, ~~$46.0~~$45.0 million is in the U.S., ~~$25.3~~$25.9 million is in Brunei, ~~$15.6~~$15.3 million is in Mexico, 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 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 ~~in response to~~from the COVID-19 ~~pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 38)~~pandemic) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $1,206.3 million to reduce the carrying values to their estimated fair values at select properties.

The fair values 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 in the applicable region.

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


	~~Nine Months Ended~~
~~(Thousands of dollars)~~	~~September 30, 2020~~
~~U.S.~~	$	~~1,152,515~~

~~Other Foreign~~	~~39,709~~
~~Corporate~~	~~14,060~~
	$	~~1,206,284~~


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

Divestments

~~In July 2019,~~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 the Company completed a divestiture of its 2 subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $960.0 million was recorded as part of discontinued operations on the Consolidated Statement of Operations during 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy was entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020, however the results were not achieved by PTTEP.

for previously incurred capital expenditures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – ~~Discontinued Operations and~~ 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 and its former U.K., U.S. refining and marketing~~ operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019~~2020 were as follows:


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
Revenues	Revenues	$	0	972,737	4,074	1,328,110	Revenues	$	144	—	$	801	4,074
Costs and expenses	Costs and expenses						Costs and expenses
Lease operating expenses		0		6,262	0	127,138
Depreciation, depletion and amortization		0		(1)	0	33,697
Other costs and expenses		778		11,079	10,981	81,560

Other costs and expenses (benefits)							Other costs and expenses (benefits)	850		778	1,401		10,981
(Loss) income before taxes	(Loss) income before taxes	(778)		955,397	(6,907)	1,085,715	(Loss) income before taxes	(706)		(778)	(600)		(6,907)
Income tax expense	Income tax expense	0		2,029	0	58,083	Income tax expense	—		—	—		—
(Loss) income from discontinued operations	(Loss) income from discontinued operations	$	(778)	953,368	(6,907)	1,027,632	(Loss) income from discontinued operations	$	(706)	(778)	$	(600)	(6,907)

~~The following table presents~~As of September 30, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the ~~major categories~~net property, plant equipment of ~~assets and liabilities of the~~CA-2 project in Brunei ~~exploration and production operations, the U.K. refining and marketing operations~~ and the Company’s office building in El Dorado, ~~Arkansas and 2 airplanes that are reflected as~~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 onincluded 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’s ~~Consolidated Balance Sheets. Subsequent to period end, 1 of the planes has been sold.~~office building in El Dorado, Arkansas.


(Thousands of dollars)	(Thousands of dollars)	September 30, 2020		December 31, 2019	(Thousands of dollars)	September 30, 2021		December 31, 2020
Current assets	Current assets				Current assets
Cash	Cash	$	29,420	25,185	Cash	$	—	10,185
Accounts receivable		425		4,834

Inventories	Inventories	406		406	Inventories	—		406
Prepaid expenses and other		831		1,882

Property, plant, and equipment, net	Property, plant, and equipment, net	68,393		82,116	Property, plant, and equipment, net	40,987		307,704
Deferred income taxes and other assets	Deferred income taxes and other assets	9,441		9,441	Deferred income taxes and other assets	—		9,441

Total current assets associated with assets held for sale	Total current assets associated with assets held for sale	$	108,916	123,864	Total current assets associated with assets held for sale	$	40,987	327,736

Current liabilities	Current liabilities				Current liabilities
Accounts payable	Accounts payable	$	5,481	3,702	Accounts payable	$	—	5,306

Other accrued liabilities					Other accrued liabilities	—		45
Current maturities of long-term debt (finance lease)	Current maturities of long-term debt (finance lease)	728		705	Current maturities of long-term debt (finance lease)	—		737
Taxes payable	Taxes payable	1,510		1,411	Taxes payable	—		1,510

Long-term debt (finance lease)	Long-term debt (finance lease)	6,702		7,240	Long-term debt (finance lease)	—		6,513
Asset retirement obligation	Asset retirement obligation	256		240	Asset retirement obligation	—		261
Total current liabilities associated with assets held for sale	Total current liabilities associated with assets held for sale	$	14,677	13,298	Total current liabilities associated with assets held for sale	$	—	14,372

Note F – Financing Arrangements and Debt

As of September 30, ~~2020,~~2021, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At September 30, ~~2020,~~2021, the Company had ~~$200.0 million~~no outstanding borrowings under the RCF and ~~$3.7~~$31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, ~~2020,~~2021, the interest rate in effect on borrowings under the facility was ~~1.84%~~1.78%. At September 30, ~~2020,~~2021, the Company was in compliance with all covenants related to the RCF.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financing Arrangements and Debt (Contd.)

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

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

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

Subsequent to quarter end, the Company issued a notice of partial redemption with respect to $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to the date of redemption. The redemption date of the 2024 Notes will be December 2, 2021.

~~Table of Contents~~

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

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.໿


		Nine Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:	Net (increase) decrease in operating working capital, excluding cash and cash equivalents:				Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹		$	251,706	(128,698)
Decrease in accounts receivable ¹					Decrease in accounts receivable ¹	$	75,100	251,706
Decrease in inventories	Decrease in inventories	4,747		4,398	Decrease in inventories	9,718		4,747
(Increase) in prepaid expenses	(Increase) in prepaid expenses	(17,400)		(3,745)	(Increase) in prepaid expenses	(6,682)		(17,400)
Increase (decrease) in accounts payable and accrued liabilities ¹	Increase (decrease) in accounts payable and accrued liabilities ¹	(264,078)		165,224	Increase (decrease) in accounts payable and accrued liabilities ¹	40,687		(264,078)
Increase (decrease) in income taxes payable		(1,236)		3,078
(Decrease) in income taxes payable					(Decrease) in income taxes payable	(1,493)		(1,236)
Net (increase) decrease in noncash operating working capital	Net (increase) decrease in noncash operating working capital	$	(26,261)	40,257	Net (increase) decrease in noncash operating working capital	$	117,330	(26,261)
Supplementary disclosures:	Supplementary disclosures:				Supplementary disclosures:
Cash income taxes paid, net of refunds	Cash income taxes paid, net of refunds	$	(12,559)	(4,563)	Cash income taxes paid, net of refunds	$	1,685	(12,559)
Interest paid, net of amounts capitalized of $5.9 million in 2020 and $0.2 million in 2019		139,651		137,116
Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020					Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020	127,793		139,651

Non-cash investing activities:	Non-cash investing activities:				Non-cash investing activities:
Asset retirement costs capitalized ²	Asset retirement costs capitalized ²	$	6,342	48,203	Asset retirement costs capitalized ²	$	36,300	6,342
(Increase) decrease in capital expenditure accrual		74,742		(52,659)
Decrease in capital expenditure accrual					Decrease in capital expenditure accrual	31,301		74,742

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

2 ~~2019 includes~~Excludes non-cash capitalized cost offset by impairment of $74.4 million in the first quarter of 2021 and a gain in other operating income of $71.8 million following a commercial agreement to sanction an asset ~~retirement obligations assumed as part~~life extension project at Terra Nova in the third quarter of 2021, which extended the ~~LLOG acquisition~~life of Terra Nova by approximately 10 years.

~~$37.3 million. See Note P.~~

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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.

On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $63.0 million due to a lower discount rate and lower plan assets compared to December 31, 2019.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020.


		Three Months Ended September 30,						Three Months Ended September 30,
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021	2020
Service cost	Service cost	$	1,664	2,064	342	421	Service cost	$	1,770	1,664	328	342
Interest cost	Interest cost	4,827		7,151	612	945	Interest cost	4,258		4,827	521	612
Expected return on plan assets	Expected return on plan assets	(5,773)		(6,455)	0	0	Expected return on plan assets	(6,038)		(5,773)	—	—
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	149		248	0	(98)	Amortization of prior service cost (credit)	155		149	—	—
Recognized actuarial loss	Recognized actuarial loss	5,690		3,516	(24)	0	Recognized actuarial loss	5,269		5,690	(8)	(24)
Net periodic benefit expense	Net periodic benefit expense	$	6,557	6,524	930	1,268	Net periodic benefit expense	$	5,414	6,557	841	930

		Nine Months Ended September 30,						Nine Months Ended September 30,
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021	2020
Service cost	Service cost	$	5,996	6,188	1,235	1,261	Service cost	$	5,306	5,996	981	1,235
Interest cost	Interest cost	16,381		21,402	2,200	2,833	Interest cost	12,844		16,381	1,563	2,200
Expected return on plan assets	Expected return on plan assets	(18,414)		(19,285)	0	0	Expected return on plan assets	(18,326)		(18,414)	—	—
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	515		741	0	(293)	Amortization of prior service cost (credit)	467		515	—	—
Recognized actuarial loss	Recognized actuarial loss	14,223		10,538	(24)	0	Recognized actuarial loss	15,829		14,223	(23)	(24)
Net periodic benefit expense	Net periodic benefit expense	18,701		19,584	3,411	3,801	Net periodic benefit expense	$	16,120	18,701	2,521	3,411
Other - curtailment	Other - curtailment	586		0	(1,825)	0	Other - curtailment	—		586	—	(1,825)
Other - special termination benefits	Other - special termination benefits	8,435		0	0	0	Other - special termination benefits	—		8,435	—	—
Total net periodic benefit expense	Total net periodic benefit expense	$	27,722	19,584	1,586	3,801	Total net periodic benefit expense	$	16,120	27,722	2,521	1,586

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

During the nine-month period ended September 30, ~~2020,~~2021, the Company made contributions of ~~$27.4~~$31.0 million to its defined benefit pension and postretirement benefit plans. Remaining funding in ~~2020~~2021 for the Company’s defined benefit pension and postretirement plans is anticipated to be ~~$10.3~~$10.9 million.

~~Table of Contents~~

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

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) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Plan 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~~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 Plan and the 2018 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of ~~5,000,000~~5000000 shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.

During the first nine months of 2021, 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

Performance Based RSUs 1

1,156,800

February 2, 2021

16.03

Monte Carlo at Grant Date

Time Based RSUs 2

385,600

February 2, 2021

12.30

Average Stock Price at Grant Date

Cash Settled RSUs 3

1,022,700

February 2, 2021

12.30

Average Stock Price at Grant Date

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 scheduled to vest over three years from the date of grant.

The Company also has a Stock Plan for Non-Employee Directors ~~(2018 NED Plan)~~that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan. All awards on or after May 12, 2021, will be made under the 2021 NED Plan.

During the first nine months of ~~2020,~~2021, the Committee granted ~~999,700 performance-based RSUs and 340,600~~the following awards to Non-Employee Directors:

2018 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

182,652

February 3, 2021

13.14

Closing Stock Price at Grant Date

1 Non-employee directors time-based RSUs to certain employees under the 2018 Long-Term Plan. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $21.51 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $21.68 per unit. Additionally, in February 2020, the Committee granted 1,152,500 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2020 was $21.68. Also, in February, the Committee granted 106,248 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 NED Plan. These units are scheduled to vest ~~on the third anniversary of the date of grant. The estimated fair value of these awards was $22.59 per unit on date of grant.~~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.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, ~~2020.~~2021.

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


		Nine Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Compensation charged against income before tax benefit	Compensation charged against income before tax benefit	$	17,542	39,884	Compensation charged against income before tax benefit	$	29,145	17,542
Related income tax benefit recognized in income	Related income tax benefit recognized in income	2,278		6,204	Related income tax benefit recognized in income	4,120		2,278

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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Earnings ~~per~~Per Share

Net (loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020. The following table reports the weighted-average shares outstanding used for these computations.


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	(Weighted-average shares)	2020	2019	2020	2019	(Weighted-average shares)	2021	2020	2021	2020
Basic method	Basic method	153,596,109	160,365,705	153,479,654	167,310,202	Basic method	154,439,313	153,596,109	154,239,440	153,479,654
Dilutive stock options and restricted stock units ¹	Dilutive stock options and restricted stock units ¹	0	614,333	0	795,025	Dilutive stock options and restricted stock units ¹	1,492,949	—	—	—
Diluted method	Diluted method	153,596,109	160,980,038	153,479,654	168,105,227	Diluted method	155,932,262	153,596,109	154,239,440	153,479,654

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

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Antidilutive stock options excluded from diluted shares	Antidilutive stock options excluded from diluted shares	2,111,068		2,903,768		2,305,973		3,016,361		Antidilutive stock options excluded from diluted shares	1,316,222		2,111,068		1,502,758		2,305,973
Weighted average price of these options	Weighted average price of these options	$	38.54	$	44.65	$	40.15	$	45.38	Weighted average price of these options	$	34.42	$	38.54	$	34.97	$	40.15

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019,~~2020, the Company’s effective income tax rates were as follows:


		2020	2019		2021	2020
Three months ended September 30,	Three months ended September 30,	19.1%	10.6%	Three months ended September 30,	21.1%	19.1%
Nine months ended September 30,	Nine months ended September 30,	18.6%	12.1%	Nine months ended September 30,	28.6%	18.6%

The effective tax rate for the three-month period ended September 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to income generated in Canada, which has a higher tax rate, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax rate on income.

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

The effective tax rate for the ~~three-month~~nine-month period ended September 30, ~~2019~~2021 was ~~below~~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 ~~income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million.~~overall loss.

The effective tax rate for the nine-month period ended September 30, 2020 was below the ~~U.S.~~ 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 effective tax rate for the nine-month period ended September 30, 2019 was below the statutory tax rate of 21% due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million, a reduction of the Alberta provincial corporate income tax rate that reduced the future deferred tax liability by $13 million, and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

~~The~~ Company’s tax returns in multiple jurisdictions are subject to audit by taxing ~~authorities.~~authorities, and currently the Company is under audit in several of these jurisdictions. 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. As of September 30, ~~2020,~~2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; Malaysia – ~~2013;~~2014; and ~~United Kingdom – 2018. Following the divestment of Malaysia in the~~

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K– Income Taxes (Contd.)

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

Note L – Financial Instruments and Risk Management

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

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

Commodity Price Risks

~~At September 30, 2020, the~~The Company ~~had 45,000 barrels per day in WTI~~has entered into crude oil ~~swap financial contracts maturing through December 2020 at an average price of $56.42,~~swaps and ~~18,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2021 at an average price of $43.31.~~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 September 30, ~~2019, the Company had 35,000 barrels~~2021, volumes per day ~~in WTI~~associated with outstanding crude oil ~~swap financial~~derivative contracts ~~maturing through December 2019 at an~~and the weighted average ~~price of $60.51 and 35,000 barrels per day in WTI crude oil swap financial~~prices for these contracts ~~maturing through December 2020 at an average price of $57.59.~~are as follows:


	September 30, 2021
	2021		2022
NYMEX WTI swap contracts:
Volume per day (Bbl):	45,000		20,000
Price per Bbl:	$	42.77	$	44.88

NYMEX WTI collar contracts:
Volume per day (Bbl):	—		16,000
Price per Bbl:
Ceiling:	$	—	$	71.83
Floor:	—		60.38

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 September 30, ~~2020~~2021 and ~~2019.~~2020.

At September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

September 30, 2020 December 31, 2019
(Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives
Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value
Commodity Accounts receivable $ 93,774 Accounts payable $ (33,364)

For the three-month and nine-month periods ended September 30, 2020 and 2019, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

Gain (Loss) Gain (Loss)
(Thousands of dollars) Statement of Operations Location Three Months Ended September 30, Nine months ended September 30,
Type of Derivative Contract 2020 2019 2020 2019
Commodity (Loss) gain on crude contracts $ (5,290) 63,247 $ 319,502 121,163

~~Interest Rate Risks~~

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During the nine-month periods ended September 30, 2020 and 2019, $1.1 million and $2.2 million, respectively, of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at September 30, 2020 was $2.0 million and is recorded, net of income taxes of $0.5 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.4 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2020.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

September 30, 2021

December 31, 2020

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity swaps

Accounts receivable

—

Accounts receivable

13,050

Accounts payable

(312,448)

Accounts payable

(89,842)

Deferred credits and other liabilities

(41,645)

Deferred credits and other liabilities

(12,833)

Commodity collars

Accounts receivable

—

Accounts receivable

—

Accounts payable

(15,929)

Accounts payable

—

For the three-month and nine-month periods ended September 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)
(Thousands of dollars)	Statement of Operations Location	Three Months Ended September 30,			Nine months ended September 30,
Type of Derivative Contract		2021		2020	2021	2020
Commodity swaps	(Loss) gain on derivative instruments	$	(43,235)	(5,290)	(483,865)	319,502
Commodity collars	(Loss) gain on derivative instruments	(15,929)		—	(15,929)	—

Fair Values – Recurring

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

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, are presented in the following table.


		September 30, 2020					December 31, 2019					September 30, 2021					December 31, 2020
(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	93,774	0	93,774	0	0	0	0
Commodity swaps											Commodity swaps	$	—	—	—	—	—	13,050	—	13,050
		$	0	93,774	0	93,774	0	0	0	0		$	—	—	—	—	—	13,050	—	13,050

Liabilities:	Liabilities:										Liabilities:
Commodity derivative contracts		$	0	0	0	0	0	33,364	0	33,364
Nonqualified employee savings plans		16,169		0	0	16,169	17,035	0	0	17,035
Commodity collars											Commodity collars	$	—	15,929	—	15,929	—	—	—	—
Nonqualified employee savings plan											Nonqualified employee savings plan	17,180		—	—	17,180	14,988	—	—	14,988
Commodity swaps											Commodity swaps	—		354,093	—	354,093	—	102,675	—	102,675
Contingent consideration	Contingent consideration	0		0	117,311	117,311	0	0	146,787	146,787	Contingent consideration	—		—	238,115	238,115	—	—	133,004	133,004
		$	16,169	0	117,311	133,480	17,035	33,364	146,787	197,186		$	17,180	370,022	238,115	625,317	14,988	102,675	133,004	250,667

The fair value of ~~WTI~~commodity (WTI crude ~~oil~~oil) derivative contracts in ~~2020~~2021 and ~~2019~~2020 were based on active market quotes for WTI crude oil. The before tax income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on ~~crude contracts~~derivative instruments in the Consolidated Statements of Operations.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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) ~~expense~~ in the Consolidated Statements of Operations. ~~Any remaining contingent~~Contingent consideration is payable ~~will be due~~ annually in years ~~2021~~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 September 30, ~~2020~~2021 and December 31, ~~2019.~~2020.

Note M – Accumulated Other Comprehensive Loss

The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, ~~2019~~2020 and September 30, ~~2020~~2021 and the changes during the nine-month period ended September 30, ~~2020,~~2021, are presented net of taxes in the following table.

~~Table of Contents~~

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

~~Note M – Accumulated Other Comprehensive Loss~~ ~~(Contd.)~~

(Thousands of dollars) Foreign
Currency
Translation
Gains (Losses) Retirement
and
Postretirement
Benefit Plan
Adjustments Deferred
Loss on
Interest Rate
Derivative
Hedges Total
Balance at December 31, 2019 $ (353,252) (218,015) (2,894) (574,161)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings (39,520) (55,707) 0 (95,227)
Reclassifications to income 0 10,488 ¹ 905 ² 11,393
Net other comprehensive income (loss) (39,520) (45,219) 905 (83,834)
Balance at September 30, 2020 $ (392,772) (263,234) (1,989) (657,995)


(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Deferred Loss on Interest Rate Derivative Hedges		Total
Balance at December 31, 2020	$	(324,011)	(275,632)		(1,690)		(601,333)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	6,534		—		—		6,534
Reclassifications to income	—		12,935	¹	1,690	²	14,625
Net other comprehensive income (loss)	6,534		12,935		1,690		21,159
Balance at September 30, 2021	$	(317,477)	(262,697)		—		(580,174)

1 Reclassifications before taxes of ~~$13,720~~ $16,282 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, ~~2020.~~2021. See Note H for additional information. Related income taxes of ~~$3,232~~ $3,347 are included in Income tax expense (benefit) for the nine-month period ended September 30, ~~2020.~~2021.

2 Reclassifications before taxes of ~~$1,147~~ $2,140 are included in Interest expense, net, for the nine-month period ended September 30, ~~2020.~~2021. Related income taxes of ~~$242~~ $450 are included in Income tax expense (benefit) for the nine-month period ended September 30, ~~2020.~~2021. See Note L for additional information.

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 ~~changes;~~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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable laws and regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings.

The Biden administration has indicated that it intends to increase regulatory oversight of the oil and gas industry, with a focus on climate change and greenhouse gas emissions (including methane emissions). The Biden administration has issued a number of executive orders that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. The Biden administration has also issued orders related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. ~~Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous~~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 priorowners 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 ~~and operational~~ matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. ~~The Company~~Murphy USA Inc. has ~~not~~ retained any environmental exposure associated with Murphy’s former U.S. marketing ~~operations.~~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/(loss),~~income, financial condition or liquidity in a future period.

~~Table of Contents~~

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

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

There is the possibility that environmental expenditures could be required at currently unidentified sites, and ~~new or revised regulations~~additional expenditures could ~~require additional expenditures~~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/(loss),~~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/ (loss),~~income, financial condition or liquidity in a future period.

~~Table of Contents~~

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

NoteO– 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), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.໿

Total Assets at September 30, 2020 Three Months Ended September 30, 2020 Three Months Ended September 30, 2019
(Millions of dollars) External
Revenues Income
(Loss) External
Revenues Income
(Loss)
Exploration and production ¹
United States $ 7,028.0 330.8 (172.6) 656.8 170.8
Canada 2,155.5 96.3 (8.6) 95.0 (9.1)
Other 264.1 0 (11.7) 1.9 (3.7)
Total exploration and production 9,447.6 427.1 (192.9) 753.7 158.0
Corporate 1,002.1 (5.2) (72.9) 63.4 0.3
Assets/revenue/income (loss) from continuing operations 10,449.7 421.9 (265.8) 817.1 158.3
Discontinued operations, net of tax 19.7 0 (0.8) 0 953.4
Total $ 10,469.4 421.9 (266.6) 817.1 1,111.7
Nine Months Ended September 30, 2020 Nine Months Ended September 30, 2019
External
Revenues Income
(Loss) External
Revenues Income
(Loss)
Exploration and production ¹
United States $ 1,070.6 (1,011.7) 1,734.3 420.0
Canada 245.2 (35.0) 323.8 (7.5)
Other 1.8 (73.0) 7.9 (35.4)
Total exploration and production 1,317.6 (1,119.7) 2,066.0 377.1
Corporate 319.5 26.9 125.6 (97.0)
Assets/revenue/income (loss) from continuing operations 1,637.1 (1,092.8) 2,191.6 280.1
Discontinued operations, net of tax 0 (6.9) 0 1,027.6
Total $ 1,637.1 (1,099.7) 2,191.6 1,307.7

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

2120

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

~~Note P – Acquisitions~~


	Total Assets at September 30, 2021		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States	$	6,586.3	565.2	168.1	330.8	(172.6)
Canada	2,241.2		124.6	73.9	96.3	(8.6)
Other	264.6		—	(5.2)	—	(11.7)
Total exploration and production	9,092.1		689.8	236.8	427.1	(192.9)
Corporate	1,237.8		(59.1)	(98.8)	(5.2)	(72.9)
Continuing operations	10,329.9		630.7	138.0	421.9	(265.8)
Discontinued operations, net of tax	1.0		—	(0.7)	—	(0.8)
Total	$	10,330.9	630.7	137.3	421.9	(266.6)

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

~~LLOG Acquisition~~1:

~~In June 2019, the Company announced the completion~~Additional details about results of ~~a transaction with LLOG Exploration Offshore L.L.C.~~oil and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.

~~Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200 million~~natural gas operations are presented in the ~~event that certain revenue thresholds are exceeded between 2019~~table on pages 25 and ~~2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.~~

26.

~~Note Q – Restructuring Charges~~

On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income during the three and nine months ended September 30, 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and 2 airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, 1 of the planes has been sold. All Restructuring charges have been recorded in the Corporate segment.

~~The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the three and nine months ended September 30, 2020:~~

(Thousands of dollars) Three Months Ended
September 30, 2020 Nine Months Ended
September 30, 2020
Severance $ 2,635 22,502
Pension and termination benefit charges 0 10,913
Contract exit costs and other 2,347 12,964
Restructuring charges $ 4,982 46,379

The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at September 30, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:


~~(Thousands of dollars)~~
~~Restructuring accruals~~	$	~~28,814~~
~~Utilizations~~	~~(19,635)~~
~~Liability at September 30, 2020~~	$	~~9,179~~

2221

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

In ~~2020~~2021, the ~~continued spread~~global distribution and administration of vaccinations in response to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to ~~disruption~~an improving global economic outlook and subsequently increased demand for oil and gas. Emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the ~~global economy and a weakness~~outlook, however in 2021 demand for ~~crude oil. In the first quarter of 2020, certain major global suppliers of crude~~ oil ~~announced~~and gas has remained resilient. The demand resilience has revealed an oil supply ~~increases which resulted in a contribution~~shortage, and hence is applying upward pressure to ~~the lower global commodity prices in the first quarter~~current and ~~early second quarter. In early second quarter of 2020, the~~future oil and gas prices.

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

Overall, the combination of OPEC+ supply constraints and the increase in demand driven by the global COVID-19 vaccine roll out has provided upward pressure to the oil price inwhich directly impacts the ~~latter part of the second quarter and during the third quarter. Nevertheless, oil prices during the third quarter 2020 remained below average 2019 prices. The reduction in commodity prices~~Company’s product revenue from sales compared to ~~2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 35.~~one year ago.

For the three months ended September 30, ~~2020,~~2021, West Texas Intermediate (WTI) crude oil prices averaged approximately ~~$41~~$70.56 per barrel (compared to ~~$28~~$66.07 in the second quarter of ~~2020~~2021 and ~~$56~~$40.93 in the third quarter of ~~2019)~~2020). The closing price for WTI at the end of the third quarter of ~~2020~~2021 was approximately ~~$40~~$71.54 per barrel, reflecting a ~~34% reduction~~modest increase from the second quarter 2021 closing price atand an 81% increase from the ~~end of 2019.~~third quarter 2020 closing price. The average price in October ~~2020~~2021 was ~~$39.55~~$81.22 per barrel. As of close on November ~~4, 2020,~~2, 2021, the NYMEX WTI forward curve ~~prices~~price for the remainder of ~~2020~~2021 and ~~2021~~2022 were ~~$39.15~~$83.91 and ~~$41.06~~$76.27 per barrel, respectively.

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

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

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

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

Table of Contents

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

Summary (contd.)

For the three months ended September 30, 2020, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $122.7 million in capital expenditures (on a value of work done basis), in the third quarter of 2020, which included $19.3 million to fund the development of the King’s Quay ~~Floating Production System (FPS).~~FPS. The Company reported net loss from continuing operations of $265.8 million ~~(which includes a~~for the third quarter of 2020. This amount included loss attributable to noncontrolling interest of $23.1 ~~million) for the third quarter~~million, after-tax impairment charges of ~~2020.~~$145.9 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $54.8 million and $11.1 million, respectively.

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

In the first quarter, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the ~~nine months ended September 30, 2020.~~

~~For the three months ended September 30, 2019, the Company produced 203 thousand barrels~~sale of ~~oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $356.6 million in capital expenditures (on a value of work done basis)~~Murphy’s entire 50% interest in the ~~third quarter~~King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of ~~2019. The Company reported net income~~project costs from ~~continuing operations~~inception to closing with proceeds of ~~$158.3 million (which includes income attributable to noncontrolling interest of $22.7 million) for the three months ended September 30, 2019.~~$267.7 million.

For the nine months ended September 30, 2019, the Company produced 179 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $2.3 billion in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $280.1 million (which includes income attributable to noncontrolling interest of $86.3 million) for the nine months ended September 30, 2019.

During the three-month and nine-month periods ended September 30, 2020, crude oil and condensate volumes from continuing operations were lower than the prior year period as a result of lower Eagle Ford Shale volumes (due to lower capital expenditures) and higher hurricane and storm downtime in the Gulf of Mexico. Revenue, compared to 2019, was also impacted by the lower average oil prices. The results are explained in more detail below.

~~Table of Contents~~

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

Results of Operations

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


		Income (Loss)						Income (Loss)
		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Millions of dollars)	(Millions of dollars)	2020		2019	2020	2019	(Millions of dollars)	2021		2020	2021	2020
Exploration and production	Exploration and production	$	(192.9)	158.0	(1,119.7)	377.1	Exploration and production	$	236.8	(192.9)	421.6	(1,119.7)
Corporate and other	Corporate and other	(72.9)		0.3	26.9	(97.0)	Corporate and other	(98.8)		(72.9)	(577.6)	26.9
(Loss) income from continuing operations		(265.8)		158.3	(1,092.8)	280.1
Income (loss) from continuing operations							Income (loss) from continuing operations	138.0		(265.8)	(156.0)	(1,092.8)
Discontinued operations ¹	Discontinued operations ¹	(0.8)		953.4	(6.9)	1,027.6	Discontinued operations ¹	(0.7)		(0.8)	(0.6)	(6.9)
Net (loss) income including noncontrolling interest		$	(266.6)	1,111.7	(1,099.7)	1,307.7
Net income (loss) including noncontrolling interest							Net income (loss) including noncontrolling interest	$	137.3	(266.6)	(156.6)	(1,099.7)

1 The Company has presented its ~~Malaysia E&P operations and~~ 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)
Three Months Ended
September 30, Nine Months Ended September 30,
(Millions of dollars) 2020 2019 2020 2019
Exploration and production
United States $ (172.6) 170.8 (1,011.7) 420.0
Canada (8.6) (9.1) (35.0) (7.5)
Other (11.7) (3.7) (73.0) (35.4)
Total $ (192.9) 158.0 (1,119.7) 377.1


	Income (Loss)
	Three Months Ended September 30,			Nine Months Ended September 30,
(Millions of dollars)	2021		2020	2021	2020
Exploration and production
United States	$	168.1	(172.6)	481.8	(1,011.7)
Canada	73.9		(8.6)	(37.7)	(35.0)
Other	(5.2)		(11.7)	(22.5)	(73.0)
Total	$	236.8	(192.9)	421.6	(1,119.7)

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 September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(Millions of dollars, except per barrel of oil equivalents sold)	(Millions of dollars, except per barrel of oil equivalents sold)	2020		2019	2020	2019	(Millions of dollars, except per barrel of oil equivalents sold)	2021		2020	2021	2020
Net (loss) income attributable to Murphy (GAAP)		$	(243.6)	1,089.0	(976.8)	1,221.5
Income tax (benefit) expense		(62.6)		18.8	(248.9)	38.7
Net income (loss) attributable to Murphy (GAAP)							Net income (loss) attributable to Murphy (GAAP)	$	108.5	(243.6)	(242.1)	(976.8)
Income tax expense (benefit)							Income tax expense (benefit)	36.8		(62.6)	(62.5)	(248.9)
Interest expense, net	Interest expense, net	45.2		44.9	124.9	145.1	Interest expense, net	46.9		45.2	178.4	124.9
Depreciation, depletion and amortization expense ¹	Depreciation, depletion and amortization expense ¹	219.7		308.3	725.1	766.4	Depreciation, depletion and amortization expense ¹	182.8		219.7	588.4	725.1
EBITDA attributable to Murphy (Non-GAAP)	EBITDA attributable to Murphy (Non-GAAP)	(41.3)		1,461.0	(375.7)	2,171.7	EBITDA attributable to Murphy (Non-GAAP)	375.0		(41.3)	462.2	(375.7)
Mark-to-market (gain) loss on derivative instruments							Mark-to-market (gain) loss on derivative instruments	(55.9)		69.3	228.5	(104.5)
Impairment of assets ¹	Impairment of assets ¹	186.5		—	1,072.5	—	Impairment of assets ¹	—		186.5	171.3	1,072.5
Mark-to-market loss (gain) on crude oil derivative contracts		69.3		(49.2)	(104.5)	(100.1)
Mark-to-market loss (gain) on contingent consideration	Mark-to-market loss (gain) on contingent consideration	14.0		(28.4)	(29.5)	0.5	Mark-to-market loss (gain) on contingent consideration	28.4		14.0	105.1	(29.5)
Asset retirement obligation (gains) losses							Asset retirement obligation (gains) losses	(71.8)		—	(71.8)	—
Accretion of asset retirement obligations ¹							Accretion of asset retirement obligations ¹	10.8		10.8	30.8	31.2
Unutilized rig charges							Unutilized rig charges	3.2		5.2	8.5	13.2
Foreign exchange (gains) losses							Foreign exchange (gains) losses	(2.8)		0.8	(1.5)	(2.5)
Discontinued operations loss							Discontinued operations loss	0.7		0.8	0.6	6.9
Restructuring expenses	Restructuring expenses	5.0		—	46.4	—	Restructuring expenses	—		5.0	—	46.4
Accretion of asset retirement obligations		10.8		10.6	31.2	29.8
Unutilized rig charges		5.2		—	13.2	—
Discontinued operations loss (income)		0.8		(953.4)	6.9	(1,027.6)
Inventory loss	Inventory loss	—		—	4.8	—	Inventory loss	—		—	—	4.8
Foreign exchange losses (gains)		0.8		0.8	(2.5)	6.4
Business development transaction costs		—		4.1	—	24.4
Write-off of previously suspended exploration wells		—		—	—	13.2
Seal insurance proceeds	Seal insurance proceeds	(1.7)		(8.0)	(1.7)	(8.0)	Seal insurance proceeds	—		(1.7)	—	(1.7)

Adjusted EBITDA attributable to Murphy (Non-GAAP)	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	249.4	437.5	661.1	1,110.3	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	287.6	249.4	933.7	661.1

Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	14,166		17,745	46,478	45,511	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	14,219		14,166	43,536	46,478

Adjusted EBITDA per barrel of oil equivalents sold	Adjusted EBITDA per barrel of oil equivalents sold	$	17.61	24.65	14.22	24.40	Adjusted EBITDA per barrel of oil equivalents sold	$	20.23	17.61	21.45	14.22

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

Table of Contents

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

Results of Operations (contd.)

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


(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended September 30, 2021
Oil and gas sales and other operating revenues	$	565.2	124.6	—	689.8
Lease operating expenses	96.7		33.4	0.1	130.2
Severance and ad valorem taxes	10.8		0.8	—	11.6
Transportation, gathering and processing	28.4		16.2	—	44.6
Depreciation, depletion and amortization	147.0		39.7	0.1	186.8

Accretion of asset retirement obligations	9.3		2.9	—	12.2
Exploration expenses
Dry holes and previously suspended exploration costs	17.3		—	—	17.3
Geological and geophysical	—		—	0.3	0.3
Other exploration	1.3		0.1	0.5	1.9
	18.6		0.1	0.8	19.5
Undeveloped lease amortization	3.1		0.1	1.8	5.0
Total exploration expenses	21.7		0.2	2.6	24.5
Selling and general expenses	4.2		4.0	1.2	9.4
Other ²	39.1		(71.7)	2.0	(30.6)
Results of operations before taxes	208.0		99.1	(6.0)	301.1
Income tax provisions (benefits)	39.9		25.2	(0.8)	64.3
Results of operations (excluding Corporate segment)	$	168.1	73.9	(5.2)	236.8

Three Months Ended September 30, 2020
Oil and gas sales and other operating revenues	$	330.8	96.3	—	427.1
Lease operating expenses	91.5		32.6	0.4	124.5
Severance and ad valorem taxes	6.4		0.3	—	6.7
Transportation, gathering and processing	29.3		12.0	—	41.3
Depreciation, depletion and amortization	166.2		59.6	0.5	226.3
Accretion of asset retirement obligations	9.4		1.4	—	10.8
Impairment of assets	205.1		—	—	205.1
Exploration expenses
Dry holes and previously suspended exploration costs	0.6		—	—	0.6
Geological and geophysical	0.1		—	(0.1)	—
Other exploration	0.6		0.1	3.6	4.3
	1.3		0.1	3.5	4.9
Undeveloped lease amortization	4.9		0.1	2.3	7.3
Total exploration expenses	6.2		0.2	5.8	12.2
Selling and general expenses	5.3		3.4	1.6	10.3
Other	22.5		(1.5)	2.5	23.5
Results of operations before taxes	(211.1)		(11.7)	(10.8)	(233.6)
Income tax (benefits) provisions	(38.5)		(3.1)	0.9	(40.7)
Results of operations (excluding Corporate segment)	$	(172.6)	(8.6)	(11.7)	(192.9)

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

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

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – ~~THREE~~NINE MONTHS ENDED SEPTEMBER 30, ~~2020~~2021 AND ~~2019~~2020


(Millions of dollars)	(Millions of dollars)	United States 1		Canada	Other	Total	(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended September 30, 2020
Nine Months Ended September 30, 2021							Nine Months Ended September 30, 2021
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	330.8	96.3	—	427.1	Oil and gas sales and other operating revenues	$	1,704.4	349.2	—	2,053.6
Lease operating expenses	Lease operating expenses	91.5		32.6	0.4	124.5	Lease operating expenses	303.3		100.0	0.4	403.7
Severance and ad valorem taxes	Severance and ad valorem taxes	6.4		0.3	—	6.7	Severance and ad valorem taxes	30.6		1.6	—	32.2
Transportation, gathering and processing	Transportation, gathering and processing	29.3		12.0	—	41.3	Transportation, gathering and processing	90.5		46.7	—	137.2
Depreciation, depletion and amortization	Depreciation, depletion and amortization	166.2		59.6	0.5	226.3	Depreciation, depletion and amortization	476.6		128.0	1.1	605.7
Impairments of assets		205.1		—	—	205.1
Accretion of asset retirement obligations	Accretion of asset retirement obligations	9.4		1.4	—	10.8	Accretion of asset retirement obligations	27.5		7.4	—	34.9
Impairment of assets							Impairment of assets	—		171.3	—	171.3
Exploration expenses							Exploration expenses
Dry holes and previously suspended exploration costs							Dry holes and previously suspended exploration costs	17.9		—	—	17.9
Geological and geophysical							Geological and geophysical	2.7		—	1.3	4.0
Other exploration							Other exploration	4.2		0.2	9.6	14.0
								24.8		0.2	10.9	35.9
Undeveloped lease amortization							Undeveloped lease amortization	7.9		0.2	5.8	13.9
Total exploration expenses							Total exploration expenses	32.7		0.4	16.7	49.8
Selling and general expenses							Selling and general expenses	15.0		12.0	4.7	31.7
Other ²							Other ²	133.5		(67.7)	(1.2)	64.6
Results of operations before taxes							Results of operations before taxes	594.7		(50.5)	(21.7)	522.5
Income tax provisions (benefits)							Income tax provisions (benefits)	112.9		(12.8)	0.8	100.9
Results of operations (excluding Corporate segment)							Results of operations (excluding Corporate segment)	$	481.8	(37.7)	(22.5)	421.6

Nine months ended September 30, 2020							Nine months ended September 30, 2020
Oil and gas sales and other operating revenues							Oil and gas sales and other operating revenues	$	1,070.6	245.2	1.8	1,317.6
Lease operating expenses							Lease operating expenses	386.5		90.6	1.2	478.3
Severance and ad valorem taxes							Severance and ad valorem taxes	21.6		1.0	—	22.6
Transportation, gathering and processing							Transportation, gathering and processing	95.4		31.4	—	126.8
Depreciation, depletion and amortization							Depreciation, depletion and amortization	589.5		161.3	1.5	752.3
Accretion of asset retirement obligations							Accretion of asset retirement obligations	27.1		4.1	—	31.2
Impairment of assets							Impairment of assets	1,152.5		—	39.7	1,192.2
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	0.6		—	—	0.6	Dry holes and previously suspended exploration costs	8.3		—	—	8.3
Geological and geophysical	Geological and geophysical	0.1		—	(0.1)	—	Geological and geophysical	9.4		0.1	4.1	13.6
Other exploration	Other exploration	0.6		0.1	3.6	4.3	Other exploration	4.3		0.4	13.1	17.8
		1.3		0.1	3.5	4.9		22.0		0.5	17.2	39.7
Undeveloped lease amortization	Undeveloped lease amortization	4.9		0.1	2.3	7.3	Undeveloped lease amortization	14.8		0.3	6.9	22.0
Total exploration expenses	Total exploration expenses	6.2		0.2	5.8	12.2	Total exploration expenses	36.8		0.8	24.1	61.7
Selling and general expenses	Selling and general expenses	5.3		3.4	1.6	10.3	Selling and general expenses	16.6		13.2	5.5	35.3
Other	Other	22.5		(1.5)	2.5	23.5	Other	1.0		(2.5)	1.4	(0.1)
Results of operations before taxes	Results of operations before taxes	(211.1)		(11.7)	(10.8)	(233.6)	Results of operations before taxes	(1,256.4)		(54.7)	(71.6)	(1,382.7)
Income tax provisions (benefits)	Income tax provisions (benefits)	(38.5)		(3.1)	0.9	(40.7)	Income tax provisions (benefits)	(244.7)		(19.7)	1.4	(263.0)
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	(172.6)	(8.6)	(11.7)	(192.9)	Results of operations (excluding Corporate segment)	$	(1,011.7)	(35.0)	(73.0)	(1,119.7)

Three Months Ended September 30, 2019
Oil and gas sales and other operating revenues		$	656.8	95.0	1.9	753.7
Lease operating expenses		116.2		31.2	0.2	147.6
Severance and ad valorem taxes		13.4		0.4	—	13.8
Transportation, gathering and processing		44.1		10.2	—	54.3
Depreciation, depletion and amortization		253.5		65.3	0.6	319.4
Accretion of asset retirement obligations		9.0		1.6	—	10.6
Exploration expenses
Dry holes and previously suspended exploration costs		(0.1)		—	—	(0.1)
Geological and geophysical		0.2		—	0.2	0.4
Other exploration		1.5		0.1	3.8	5.4
		1.6		0.1	4.0	5.7
Undeveloped lease amortization		5.2		0.3	1.0	6.5
Total exploration expenses		6.8		0.4	5.0	12.2
Selling and general expenses		22.7		7.6	5.6	35.9
Other		(21.0)		(7.3)	0.5	(27.8)
Results of operations before taxes		212.1		(14.4)	(10.0)	187.7
Income tax provisions (benefits)		41.3		(5.3)	(6.3)	29.7
Results of operations (excluding Corporate segment)		$	170.8	(9.1)	(3.7)	158.0

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

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

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2020 AND 2019~~

(Millions of dollars)
United
States 1
Canada Other Total
Nine Months Ended September 30, 2020
Oil and gas sales and other operating revenues $ 1,070.6 245.2 1.8 1,317.6
Lease operating expenses 386.5 90.6 1.2 478.3
Severance and ad valorem taxes 21.6 1.0 — 22.6
Transportation, gathering and processing 95.4 31.4 — 126.8
Depreciation, depletion and amortization 589.5 161.3 1.5 752.3
Impairment of assets 1,152.5 — 39.7 1,192.2
Accretion of asset retirement obligations 27.1 4.1 — 31.2
Exploration expenses
Dry holes and previously suspended exploration costs 8.3 — — 8.3
Geological and geophysical 9.4 0.1 4.1 13.6
Other exploration 4.3 0.4 13.1 17.8
22.0 0.5 17.2 39.7
Undeveloped lease amortization 14.8 0.3 6.9 22.0
Total exploration expenses 36.8 0.8 24.1 61.7
Selling and general expenses 16.6 13.2 5.5 35.3
Other 1.0 (2.5) 1.4 (0.1)
Results of operations before taxes (1,256.4) (54.7) (71.6) (1,382.7)
Income tax provisions (benefits) (244.7) (19.7) 1.4 (263.0)
Results of operations (excluding Corporate segment) $ (1,011.7) (35.0) (73.0) (1,119.7)
Nine months ended September 30, 2019
Oil and gas sales and other operating revenues $ 1,734.3 323.8 7.9 2,066.0
Lease operating expenses 308.3 107.1 1.1 416.5
Severance and ad valorem taxes 36.0 1.0 — 37.0
Transportation, gathering and processing 103.4 25.3 — 128.7
Depreciation, depletion and amortization 618.6 181.6 2.9 803.1
Accretion of asset retirement obligations 25.2 4.6 — 29.8
Exploration expenses
Dry holes and previously suspended exploration costs (0.2) — 13.1 12.9
Geological and geophysical 16.1 — 8.1 24.2
Other exploration 5.5 0.3 10.9 16.7
21.4 0.3 32.1 53.8
Undeveloped lease amortization 18.0 1.0 2.7 21.7
Total exploration expenses 39.4 1.3 34.8 75.5
Selling and general expenses 52.9 21.3 17.3 91.5
Other 37.5 (6.9) 0.9 31.5
Results of operations before taxes 513.0 (11.5) (49.1) 452.4
Income tax provisions (benefits) 93.0 (4.0) (13.7) 75.3
Results of operations (excluding Corporate segment) $ 420.0 (7.5) (35.4) 377.1

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

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

Results of Operations (contd.)

Exploration and Production

Third quarter ~~2020~~2021 vs. ~~2019~~2020

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

United States E&P operations reported earnings of $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of ~~2020~~2020. Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A: $19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of ~~$170.8 million~~Hurricane Ida in the third quarter of ~~2019. Results were $343.4 million unfavorable~~2021 is offset by the impact of multiple storms that occurred in the ~~2020~~third quarter ~~compared to the 2019 period~~of 2020. Lower impairment charges were due to ~~lower revenues ($326.0 million) and higher~~ impairment charges ($205.1 million), partially offset by lower depreciation, depletion and amortization ($87.3 million), income tax expense ($79.8 million), lease operating expenses ($24.7 million), general and administrative (G&A: $17.4 million), and transportation, gathering, and processing expenses ($14.8 million). Lower revenues were primarily due to lower commodity prices, lower Eagle Ford Shale volumes (due to lower capital expenditures), and lower volumesrecognized in the ~~U.S. Gulf of Mexico (as a result of shut-ins due~~prior period related to ~~hurricane activity in the 2020 quarter). The impairment charge in the quarter relates to the~~ Gulf of Mexico Cascade & Chinook field ~~which, primarily as~~and no such charges in current period. Lower DD&A is a result of ~~lower commodity prices and lower capital expenditure plans, was written down~~the prior year impairment charge reducing the depreciable asset base. Higher income tax expense is a result of pre-tax profits principally due to ~~its expected future value. Lower depreciation~~the recovering oil price. Higher other operating expense ~~was~~is primarily due to ~~lower depreciation rates following the impairment charges incurred in the first quarter~~unfavorable mark to market revaluation on contingent consideration (as a result of ~~2020 and lower sales volume. Lower lease operating expense was primarily attributable~~higher commodity prices) related to ~~wells being shut-in in the~~prior Gulf of Mexico ~~and certain cost-savings initiatives taken across all businesses. Lower G&A~~(GOM) acquisitions. Higher exploration expense is primarily due to ~~cost reductions and lower headcount as a result of restructuring (primarily closing~~dry hole costs related to Silverback in the ~~El Dorado and Calgary offices).~~current period.

Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter ~~2020 compared to a loss~~ of ~~$9.1 million in the 2019 quarter.~~2020. Results were favorable ~~$0.5~~$82.5 million compared to the ~~2019~~2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($~~1.3~~28.3 million), and lower ~~depreciation and amortization~~DD&A ($~~5.7 million), higher tax benefit ($2.2~~19.9 million), partially offset by ~~lower other operating income~~higher tax expense ($~~5.8~~28.3 million), and higher transportation, gathering and processing ~~expenses~~ ($~~1.8 million), and higher lease operating expenses ($1.4~~4.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper ~~Kaybob, and Placid (higher AECO prices in the quarter).~~Montney. Lower ~~depreciation expense~~DD&A is due to lower production volumes at ~~Tupper~~Kaybob Duvernay due to normal well decline. Higher transportation, gathering and ~~Terra-Nova (shut-in starting in December 2019). Terra Nova is~~processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be ~~shut-in for~~utilized by growth at Tupper Montney in the ~~remainder of 2020 for Asset Integrity work.~~future.

Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of ~~2020 compared to a net a loss of $3.7 million in the prior year quarter.~~2020. The result was ~~$8.0~~$6.5 million ~~unfavorable~~favorable in the ~~2020~~2021 period versus ~~2019~~2020 primarily due ~~higher prior period revenue~~lower exploration expenses in ~~Brunei~~Brazil and ~~a prior year income tax credit related to Vietnam exploration spend.~~Mexico.

Nine months 2021 vs. 2020 ~~vs.2019~~

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

United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of ~~2020 compared to income of $420 million in the first nine months of 2019.~~2020. Results were ~~$1,431.7~~$1,493.5 million ~~unfavorable~~favorable in ~~the 2020~~2021 period compared to the ~~2019~~2020 period primarily due to anno impairment ~~charge~~charges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($~~1,152.5~~633.8 million), lower ~~revenues~~DD&A ($~~663.7~~112.9 million), ~~higher~~lower lease operating expenses ~~($78.2~~(LOE: $83.2 million), partially offset by ~~lower~~higher income tax expense ($~~337.7~~357.6 million), and higher other operating expense ($~~36.5 million), G&A ($36.3 million), depreciation, depletion and amortization (DD&A: $29.1 million), and transportation, gathering, and processing charges ($8.0~~132.5 million). The impairment charge isin the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of ~~decreased~~lower oil demand (COVID-19 impact) and ~~increased~~abundant oil supply ~~(as discussed above). Based on an evaluation~~at the time of ~~expected future cash flows from properties as~~the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. The production impact of September 30, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recordedHurricane Ida in the ~~future.~~third quarter of 2021 is offset by the impact of multiple storms that occurred in 2020. Lower ~~revenues~~DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to ~~lower commodity prices year over year and lower volumes~~higher GOM workover costs in the ~~U.S. Gulf of Mexico (as a result of shut-ins related to hurricanes and storms). Higher lease operating expenses were due primarily to well workovers~~prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). ~~Lower~~Higher income tax expense is a result of higher pre-tax ~~losses driven by the impairment charge~~income principally due to higher oil price and lower ~~commodity prices. Lower~~DD&A and LOE. Higher other operating expense is primarily due to ~~a favorable~~an unfavorable mark to market revaluation on contingent consideration ~~(as~~($105.1 million; as a result of ~~lower~~higher commodity prices) from prior ~~Gulf of Mexico (GOM) acquisitions ($29.5 million). Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).~~GOM acquisitions.

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

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

Results of Operations (contd.)

expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss of ~~$7.5~~$22.5 million in the first nine months of ~~2019.~~2021 compared to a loss of $73.0 million in the prior year. Results were ~~unfavorable $27.5~~$50.5 million favorable compared to the ~~2019~~2020 period primarily due to ~~lower revenue ($78.6 million)~~no repeat of an impairment charge of $39.7 million in the prior year.

Corporate

Third quarter 2021 vs. 2020

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020. The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $59.2 million loss; 2020: $5.3 million loss), partially offset by lower ~~lease operating expense~~impairment charges ($~~16.5~~14.1 million), higher tax benefits ($5.7 million), lower ~~DD&A~~restructuring charges ($~~20.3~~5.0 million), and lower DD&A ($2.3 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Higher income tax ~~charges ($15.7 million). Lower revenues were~~benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.

Nine months 2021 vs. 2020

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

Production Volumes and Prices

Third quarter 2021 vs. 2020

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

Average crude oil and condensate ~~prices versus~~production from continuing operations was 88,245 barrels per day in the ~~prior year and a shut-in at Terra Nova for Asset Integrity work (starting~~third quarter of 2021 compared to 95,391 barrels per day in ~~December 2019 and expected~~the third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to ~~continue through 2020 full year). Lower lease operating expenses and~~Kaybob Duvernay well decline), lower ~~DD&A were~~volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of ~~lower sales.~~Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a

Table of Contents

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

Results of Operations (contd.)

Other international E&P operations reported a loss from continuing operations of $73 million in the first nine months of 2020 compared to a net loss of $35.4 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.

~~Corporate~~

On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income. These costs include severance, relocation, IT costs, pension curtailment, termination charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, one of the planes has been sold.

~~Third quarter 2020 vs. 2019~~

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $72.9 million in the third quarter 2020 compared to net income of $0.3 million in the 2019 quarter. The $73.2 million unfavorable variance is principally due to 2020 mark to market losses on forward swap commodity contracts ($69.4 million) compared to gains on forward contracts ($49.2 million) in the third quarter of 2019, impairment of the El Dorado office building ($14.1 million), and restructuring charges ($5.0 million), partially offset by higher realized gains on forward commodity contracts ($50.1 million) and a higher tax credit ($10.9 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. Higher realized gains on forward commodity contracts are due to lower prices versus the fixed contract price.

~~Nine months 2020 vs. 2019~~

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported earnings of $26.9 million in the first nine months of 2020 compared to a loss of $97.0 million in the first nine months of 2019. The $123.9 million favorable variance is primarily due to higher realized gains on forward swap commodity contracts ($194.0 million), lower interest charges ($20.6 million), lower G&A ($15.7 million), and partially offset by higher tax charges ($50.7 million) and restructuring charges ($46.4 million) related to the closure of the El Dorado and Calgary offices. Higher realized gains on forward swap commodity contracts are due to lower market pricing whereby the contract provides the Company with a fixed price. Interest charges are lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020. As of September 30, 2020, the average forward NYMEX WTI price for the remainder of 2020 was $40.35 and for 2021 was $42.21 (versus fixed hedge prices of $56.42 and $43.31; see below).

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~Production Volumes and Prices~~

~~Third quarter 2020 vs. 2019~~

Total hydrocarbon production from continuing operations averaged 162,824 barrels of oil equivalent per day in the third quarter of 2020, which represented a 20% decrease from the 203,035 barrels per day produced in third quarter 2019. The decrease was principally due to GOM shut-in production due to hurricanes (14.2 MBOED) and lower Eagle Ford Shale production (16.2 MBOED, as a result of lower capex spend at this property).

Average crude oil and condensate production from continuing operations was 95,391 barrels per day in the third quarter of 2020 compared to 122,950 barrels per day in the third quarter of 2019. The decrease of 27,559 barrels per day was principally due to lower Eagle Ford Shale production due to lower capital expenditures (15,731 barrels per day) and lower volumes in the Gulf of Mexico (14,066 barrels per day) due to GOM shut-in production due to hurricanes (11.1 MBOED). On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$39.79~~$68.88 per barrel in the third quarter ~~2020~~2021 compared to ~~$59.47~~$39.79 per barrel in the ~~2019~~2020 period, ~~a decrease~~an increase of ~~33%~~73% quarter over quarter.

Total production of natural gas liquids (NGL) from continuing operations was ~~10,523~~10,391 barrels per day in the third quarter ~~2020~~2021 compared to ~~13,601~~10,523 barrels per day in the ~~2019~~2020 period. The average sales price for U.S. NGL was ~~$14.78~~$32.01 per barrel in the ~~2020~~2021 quarter compared to ~~$13.26~~$13.91 per barrel in ~~2019.~~2020. The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in ~~the 2020 quarter compared to $21.03 per barrel in 2019.~~2020. NGL prices are higher in Canada due to the higher value of the product ~~produced~~ at the Kaybob Duvernay and Placid Montney assets.

Natural gas ~~sales~~production volumes from continuing operations averaged ~~341~~387.5 million cubic feet per day (MMCFD) in the third quarter ~~2020~~2021 compared to ~~399~~341.5 MMCFD in ~~2019.~~2020. The ~~decrease~~increase of 5746 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico ~~(20~~(7 MMCFD) and ~~lower~~in the Eagle Ford Shale (4 MMCFD). Higher natural gas volumes in Canada ~~(36 MMCFD).~~are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Lower volumes in the Gulf of Mexico are principally due to ~~GOM shut-in production due to hurricanes. Lower volumes in Canada are due to normal well decline and no additional wells in third quarter~~facility shut-ins as a result of ~~2020.~~Hurricane Ida.

Natural gas prices for the total Company averaged ~~$1.78~~$2.78 per thousand cubic feet (MCF) in the ~~2020~~2021 quarter, versus ~~$1.46~~$1.78 per MCF average in the same quarter of ~~2019.~~2020. Average natural gas prices in the USU.S. and Canada in the quarter were ~~$1.94~~$3.99 and ~~$1.74~~$2.47 per MCF, respectively.

Nine months ~~2020~~2021 vs. ~~2019~~2020

Total hydrocarbon production from all E&P continuing operations averaged ~~180,443~~170,209 barrels of oil equivalent per day in the first nine months of ~~2020,~~2021, which represented a ~~1% increase~~6% decrease from the ~~178,658~~180,443 barrels per day produced in the first nine months of ~~2019.~~2020. The ~~increase~~decrease in production is principally due to ~~the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.~~lower capital expenditures throughout 2020 to support generating positive free cashflow.

Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of ~~2020 compared to 110,762 barrels per day in the first nine months of 2019.~~2020. The decrease of ~~2,084~~10,364 barrels per day was principally due to lower ~~Eagle Ford Shale production (5,311 barrels per day), offset by higher volumes in the~~ Gulf of Mexico ~~(3,111~~production (5,472 barrels per day) due to temporary operational issues at the ~~acquisition~~Cascade & Chinook and Kodiak fields in the first quarter of ~~assets~~2021 and facility shut-ins as ~~part~~a result of Hurricane Ida in the ~~LLOG acquisition.~~third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$36.88~~$64.19 per barrel in the first nine months of ~~2020~~2021 compared to ~~$60.94~~$36.88 per barrel in the ~~2019~~2020 period, ~~a decrease~~an increase of ~~39%~~74% year over year.

Total production of natural gas liquids (NGL) from continuing operations was ~~11,901~~10,498 barrels per day in the first nine months of ~~2020~~2021 compared to ~~10,990~~11,901 barrels per day in the ~~2019~~2020 period. The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in ~~2020 compared to $15.22 per barrel in 2019.~~2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 per barrel in ~~2020 compared to $27.50 per barrel in 2019.~~2020. NGL prices are higher in Canada due to the higher value of the product ~~produced~~ at the Kaybob Duvernay and Placid Montney assets.

Natural gas sales volumes from continuing operations averaged ~~359~~368.4 million cubic feet per day (MMCFD) in the first nine months of ~~2020~~2021 compared to ~~341~~359.2 MMCFD in ~~2019.~~2020. The increase of 189.2 MMCFD was a primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico ~~(24~~(4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). ~~Higher~~Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the ~~acquisition~~Cascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of ~~assets related to~~a winter storm impacting Eagle Ford Shale production in the ~~LLOG transaction.~~

first quarter of 2021. Natural gas prices for the total Company averaged ~~$1.68~~$2.56 per thousand cubic feet (MCF) in the first nine months of ~~2020,~~2021, versus ~~$1.72~~$1.68 per MCF average in the same period of ~~2019.~~2020. Average natural gas prices in the USU.S. and Canada in the quarter were ~~$1.87~~$3.26 and ~~$1.62,~~$2.33, respectively.

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

3029

Table of Contents

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

Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020.


			Three Months Ended September 30,		Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted		2020	2019	2020	2019	Barrels per day unless otherwise noted		2021	2020	2021	2020
Continuing operations	Continuing operations						Continuing operations
Net crude oil and condensate	Net crude oil and condensate						Net crude oil and condensate
United States	United States	Onshore	24,851	40,582	27,945	33,256	United States	Onshore	26,193	24,851	26,552	27,945
		Gulf of Mexico 1	56,517	70,583	67,377	64,266		Gulf of Mexico 1	53,011	56,517	61,905	67,377
Canada	Canada	Onshore	9,595	7,101	8,106	6,503	Canada	Onshore	4,963	9,595	5,598	8,106
		Offshore	4,428	4,333	5,136	6,302		Offshore	3,779	4,428	4,016	5,136
Other	Other		—	351	114	435	Other		299	—	243	114
Total net crude oil and condensate - continuing operations	Total net crude oil and condensate - continuing operations		95,391	122,950	108,678	110,762	Total net crude oil and condensate - continuing operations		88,245	95,391	98,314	108,678
Net natural gas liquids	Net natural gas liquids						Net natural gas liquids
United States	United States	Onshore	5,489	5,582	5,459	5,621	United States	Onshore	5,847	5,489	5,043	5,459
		Gulf of Mexico 1	3,521	6,597	5,131	4,172		Gulf of Mexico 1	3,459	3,521	4,296	5,131
Canada	Canada	Onshore	1,513	1,422	1,311	1,197	Canada	Onshore	1,085	1,513	1,159	1,311
Total net natural gas liquids - continuing operations	Total net natural gas liquids - continuing operations		10,523	13,601	11,901	10,990	Total net natural gas liquids - continuing operations		10,391	10,523	10,498	11,901
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	27,520	29,122	29,054	30,203	United States	Onshore	31,478	27,520	27,750	29,054
		Gulf of Mexico 1	53,046	72,897	67,850	44,029		Gulf of Mexico 1	46,339	53,046	63,557	67,850
Canada	Canada	Onshore	260,895	296,883	262,279	267,205	Canada	Onshore	309,709	260,895	277,077	262,279
Total net natural gas - continuing operations	Total net natural gas - continuing operations		341,461	398,902	359,183	341,437	Total net natural gas - continuing operations		387,526	341,461	368,384	359,183
Total net hydrocarbons - continuing operations including NCI 2,3	Total net hydrocarbons - continuing operations including NCI 2,3		162,824	203,035	180,443	178,658	Total net hydrocarbons - continuing operations including NCI 2,3		163,224	162,824	170,209	180,443
Noncontrolling interest	Noncontrolling interest						Noncontrolling interest
Net crude oil and condensate – barrels per day	Net crude oil and condensate – barrels per day		(9,298)	(10,322)	(10,674)	(11,215)	Net crude oil and condensate – barrels per day		(7,546)	(9,298)	(8,834)	(10,674)
Net natural gas liquids – barrels per day	Net natural gas liquids – barrels per day		(327)	(478)	(443)	(496)	Net natural gas liquids – barrels per day		(243)	(327)	(322)	(443)
Net natural gas – thousands of cubic feet per day			(3,269)	(3,403)	(4,137)	(3,933)
Net natural gas – thousands of cubic feet per day 2							Net natural gas – thousands of cubic feet per day 2		(2,331)	(3,269)	(3,498)	(4,137)
Total noncontrolling interest	Total noncontrolling interest		(10,170)	(11,367)	(11,807)	(12,367)	Total noncontrolling interest		(8,178)	(10,170)	(9,739)	(11,807)
Total net hydrocarbons - continuing operations excluding NCI 2,3	Total net hydrocarbons - continuing operations excluding NCI 2,3		152,654	191,668	168,636	166,292	Total net hydrocarbons - continuing operations excluding NCI 2,3		155,046	152,654	160,470	168,636
Discontinued operations
Net crude oil and condensate – barrels per day			—	1,748	—	16,331
Net natural gas liquids – barrels per day			—	37	—	434
Net natural gas – thousands of cubic feet per day 2			—	9,624	—	67,863
Total discontinued operations			—	3,389	—	28,076
Total net hydrocarbons produced excluding NCI 2,3			152,654	195,057	168,636	194,367

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.

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~The following table contains hydrocarbons sold during the three-month and nine-month periods ended September 30, 2020 and 2019.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
Barrels per day unless otherwise noted 2020 2019 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 24,851 40,582 27,945 33,256
Gulf of Mexico 1
57,756 71,380 68,436 64,532
Canada Onshore 9,595 7,101 8,106 6,503
Offshore 4,757 4,945 5,290 6,523
Other — 309 104 415
Total net crude oil and condensate - continuing operations 96,959 124,317 109,881 111,229
Net natural gas liquids
United States Onshore 5,489 5,582 5,459 5,622
Gulf of Mexico 1
3,521 6,597 5,131 4,172
Canada Onshore 1,513 1,422 1,311 1,197
Total net natural gas liquids - continuing operations 10,523 13,601 11,901 10,991
Net natural gas – thousands of cubic feet per day
United States Onshore 27,520 29,122 29,054 30,203
Gulf of Mexico 1
53,046 72,897 67,850 44,029
Canada Onshore 260,895 296,882 262,279 267,205
Total net natural gas - continuing operations 341,461 398,901 359,183 341,437
Total net hydrocarbons - continuing operations including NCI 2,3
164,392 204,402 181,646 179,126
Noncontrolling interest
Net crude oil and condensate – barrels per day (9,545) (10,481) (10,886) (11,269)
Net natural gas liquids – barrels per day (327) (478) (443) (496)
Net natural gas – thousands of cubic feet per day 2
(3,269) (3,403) (4,137) (3,933)
Total noncontrolling interest (10,417) (11,526) (12,019) (12,421)
Total net hydrocarbons - continuing operations excluding NCI 2,3
153,975 192,875 169,627 166,706
Discontinued operations
Net crude oil and condensate – barrels per day — 1,424 — 16,177
Net natural gas liquids – barrels per day — 32 — 395
Net natural gas – thousands of cubic feet per day 2
— 9,624 — 67,863
Total discontinued operations — 3,060 — 27,883
Total net hydrocarbons sold excluding NCI 2,3
153,975 195,935 169,627 194,588

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

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

3 ~~NCI – noncontrolling interest in MP GOM.~~

3230

Table of Contents

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

Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020.໿ Comparative periods are conformed to current presentation.


			Three Months Ended September 30,			Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
			2020		2019	2020	2019			2021	2020	2021	2020
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	$	37.83	58.80	35.56	60.33	United States	Onshore	69.30	37.83	64.16	35.56
		Gulf of Mexico 1	40.82		60.69	38.08	61.90		Gulf of Mexico 1	68.93	40.82	64.44	38.08
Canada 2	Canada 2	Onshore	36.65		48.61	30.29	49.98	Canada 2	Onshore	63.76	36.65	58.70	30.29
		Offshore	43.81		62.44	37.85	64.97		Offshore	72.64	43.81	68.93	37.85
Other	Other		—		67.96	63.51	69.86	Other		—	—	—	63.51
Natural gas liquids – dollars per barrel	Natural gas liquids – dollars per barrel							Natural gas liquids – dollars per barrel
United States	United States	Onshore	13.39		10.82	10.78	14.66	United States	Onshore	30.37	13.39	24.29	10.78
		Gulf of Mexico 1	14.71		13.86	9.43	15.96		Gulf of Mexico 1	34.71	14.71	27.17	9.43
Canada 2	Canada 2	Onshore	19.97		21.03	16.95	27.50	Canada 2	Onshore	45.12	19.97	37.05	16.95
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	1.78		2.18	1.76	2.51	United States	Onshore	3.85	1.78	3.23	1.76
		Gulf of Mexico 1	2.01		2.37	1.91	2.46		Gulf of Mexico 1	4.09	2.01	3.28	1.91
Canada 2	Canada 2	Onshore	1.74		1.16	1.62	1.50	Canada 2	Onshore	2.47	1.74	2.33	1.62
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia 3		Sarawak	—		—	—	70.39
		Block K	—		69.24	—	65.75
Natural gas liquids – dollars per barrel
Malaysia 3		Sarawak	—		54.11	—	48.23
Natural gas – dollars per thousand cubic feet
Malaysia 3		Sarawak	—		3.69	—	3.60
		Block K	—		0.23	—	0.24

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

2 U.S. dollar equivalent.

3 ~~Prices are net of payments under the terms of the respective production sharing contracts~~.

Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was ~~$578.0~~$1,091.3 million for the first nine months of ~~2020~~2021 compared to ~~$1,153.2~~$578.0 million during the same period in ~~2019.~~2020. The ~~decreased~~increased cash from operating activities is primarily attributable to ~~lower~~higher revenue from sales to customers ($~~748.5~~727.3 million) ~~and higher~~, lower working capital ($143.6 million), lower lease operating ~~expenses~~expense ($~~61.8~~74.6 million), and lower general and administrative and cash restructuring expense ($47.4 million), partially offset by higher cash payments ~~received~~made on forward swap commodity contracts ~~($194.0~~(2021: realized loss of $271.3 million; 2020: realized gain of $215.0 million) ~~and lower general and administrative expenses ($71.9 million)~~. ~~See above for explanation of underlying business reasons.~~

Cash Required by Investing Activities

~~Cash~~Net cash required by ~~property~~investing activities was $311.9 million for the first nine months of 2021 compared to $723.7 million during the same period in 2020. Property additions and dry ~~holes,~~hole costs, which includes amounts expensed, were ~~$723.7~~$582.0 million and ~~$2,203.0~~$723.7 million in the ~~nine-month periods ended September 30,~~first nine months of 2021 and 2020, ~~and 2019,~~ respectively. ~~In 2020, property additions~~These amounts include $17.7 million and $74.9 million used to fund the development of the King’s Quay FPS in the first nine months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which ~~is expected to be refunded on~~reimbursed the ~~closing of a transaction to sell this asset to a third party. In 2019, property additions included the LLOG acquisition.~~Company for previously incurred capital expenditures. Lower property additions in ~~2020~~2021 are ~~a result of~~principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay.

3331

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

Financial Condition (contd.)

~~reducing the 2020 capital spending budget in response to the current commodity price environment. See Outlook section on page 35 for further details.~~

Total accrual basis capital expenditures were as follows:


		Nine Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	(Millions of dollars)	2020		2019	(Millions of dollars)	2021		2020
Capital Expenditures	Capital Expenditures				Capital Expenditures
Exploration and production	Exploration and production	$	671.0	2,320.6	Exploration and production	$	556.0	671.0
Corporate	Corporate	9.3		8.5	Corporate	12.7		9.3
Total capital expenditures	Total capital expenditures	$	680.3	2,329.1	Total capital expenditures	$	568.7	680.3

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


		Nine Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	(Millions of dollars)	2020		2019	(Millions of dollars)	2021		2020
Property additions and dry hole costs per cash flow statements	Property additions and dry hole costs per cash flow statements	$	648.7	995.5	Property additions and dry hole costs per cash flow statements	$	564.2	648.7
Property additions King's Quay per cash flow statements	Property additions King's Quay per cash flow statements	74.9		13.6	Property additions King's Quay per cash flow statements	17.7		74.9
Acquisition of oil and gas properties		—		1,226.1

Geophysical and other exploration expenses	Geophysical and other exploration expenses	26.8		36.6	Geophysical and other exploration expenses	13.3		26.8
Capital expenditure accrual changes and other	Capital expenditure accrual changes and other	(70.2)		57.1	Capital expenditure accrual changes and other	(26.6)		(70.2)
Total capital expenditures	Total capital expenditures	$	680.3	2,329.1	Total capital expenditures	$	568.7	680.3

Capital expenditures in the exploration and production business in ~~2020~~2021 compared to ~~2019~~2020 have decreased as a result of ~~the 2019 LLOG acquisition and in response to the current commodity price environment, with significant~~ capital expenditure reductions ~~in the Eagle Ford Shale. The King’s Quay FPS development project is expected~~ to ~~be refunded on the closing of a transaction to sell this asset to a third party.~~support generating positive free cash flow.

Cash Used in/ Provided by Financing Activities

Net cash ~~provided~~required by financing activities was ~~$59.1~~$585.6 million for the first nine months of ~~2020~~2021 compared to net cash ~~required~~provided by financing activities of ~~$961.4~~$59.1 million during the same period in ~~2019.~~ 2020. In 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).

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

In 2020, the cash provided by financing activities was principally from ~~net~~ borrowings on the Company’s unsecured ~~RCF~~revolving credit facility ($~~200.0 million at~~450.0 million), offset by repayments on the ~~end of the third quarter 2020). In 2019, the cash required by financing activities was principally from borrowings on our revolver and short-term loan~~revolving credit facility ($~~1,575.0~~250.0 million) to fund the LLOG acquisition. These borrowings, along with the opening revolver balance ($325.0 million) of $1,900.0 million were repaid in July 2019 following the completion of the Malaysia divestment. Total, cash dividends to shareholders ~~amounted~~($76.8 million), and distributions to $76.8 million for the nine months ended September 30, 2020 compared to $125.4 million in the same period of 2019 due to a 50% reduction in the quarterly dividend effective in the second quarter 2020 and cash used for share repurchases of $405.9 million throughout 2019. As of September 30, 2020 and in the event it is required to fund investing or operating activities from borrowings, the Company has $1,396.3 million available on its committed RCF.our noncontrolling interest ($43.7 million).

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, ~~2020~~2021 was ~~$30.0~~a deficit of $344.9 million, ~~$109.1~~$315.5 million ~~higher~~lower than December 31, ~~2019,~~2020, with the ~~increase~~decrease primarily attributable to ~~lower~~higher accounts payable ~~$306.7 million and lower~~($208.3 million), higher other accrued liabilities ~~$39.9 million,~~($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a ~~lower~~higher cash balance ($~~87.1~~194.5 million) and lower accounts receivable ($~~147.5~~75.3 million). ~~Lower~~Higher accounts payable is primarily due to ~~lower capital activity.~~the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions). 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. Lower accounts receivable isare principally due to ~~lower commodity sales prices.~~

~~Capital Employed~~

~~At September 30, 2020, long-term debt~~the timing of ~~$2,987.1 million had increased by $183.7 million compared~~cash received from our joint venture partners to ~~December 31, 2019, as a result of net borrowing on the RCF. The fixed-rate notes had a weighted average maturity of 7.0 years and a weighted average coupon of 5.9 percent.~~fund joint operations.

3432

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

Financial Condition (contd.)

Capital Employed

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

A summary of capital employed at September 30, ~~2020~~2021 and December 31, ~~2019~~2020 follows.


		September 30, 2020				December 31, 2019					September 30, 2021				December 31, 2020
(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	$	2,987.1	40.7	%	$	2,803.4	33.9	%	Long-term debt	$	2,613.7	39.8	%	$	2,988.1	41.5	%
Murphy shareholders' equity	Murphy shareholders' equity	4,343.4		59.3	%	5,467.5		66.1	%	Murphy shareholders' equity	3,949.5		60.2	%	4,214.3		58.5	%
Total capital employed	Total capital employed	$	7,330.5	100.0	%	$	8,270.8	100.0	%	Total capital employed	$	6,563.2	100.0	%	$	7,202.4	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. At September 30, ~~2020,~~2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$56.6~~$119.4 million in ~~Canada. In addition, $18.4~~Canada and $6.2 million ~~of cash was held~~ in ~~the United Kingdom and $11.0 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at September 30, 2020).~~Brunei. 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, average crude oil prices ~~recovered~~continued to recover during the ~~third quarter~~second half of 2021 versus 2020 ~~from the low seen in the second quarter of 2020.~~(Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93). As of close on November ~~4, 2020,~~2, 2021, the NYMEX WTI forward curve ~~prices~~price for the remainder of ~~2020~~2021 and ~~2021~~2022 were ~~$39.15~~$83.91 and ~~$41.06~~$76.27 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and ~~other economic factors~~OPEC+ decisions) may have on future commodity pricing. Lower prices, ~~are expected to~~should they occur, will result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between ~~146~~145.5 and ~~154~~153.5 MBOEPD, excluding ~~NCI. If price volatility persists, the Company will review the option of production curtailments~~noncontrolling interest (NCI).

The Company’s capital expenditure spend for 2021 is expected to ~~avoid incurring losses on certain produced barrels.~~

~~In response to the COVID-19 pandemic~~be between $675.0 million and ~~reduced commodity prices, the Company reduced 2020~~$685.0 million. Capital and other expenditures are routinely reviewed and planned capital expenditures ~~significantly from~~may be adjusted to reflect differences between budgeted and forecast cash flow during the ~~original plan of $1.4 billion to $1.5 billion to~~year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a ~~range of $680 million to $720 million, excluding NCI. The Company has also embarked on a cost reduction plan for both future direct operational expenditures and general and administrative costs.~~budget is prepared. The Company will primarily fund its remaining capital program in ~~2020~~2021 using operating cash flow ~~but will supplement funding where necessary with~~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 ~~available revolving credit facility.~~ year to maintain funding of the Company’s ongoing development projects.

The Company ~~is closely monitoring~~plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt.

The Company continues to monitor the impact of ~~lower~~ 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’s response~~Company continues to monitor the effects of the COVID-19 pandemic and is ~~discussed in more detail in~~encouraged by the ~~risk factors on page 38.~~ progress of the vaccination roll-outs globally.

As of November ~~4, 2020,~~2, 2021, 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

$56.42

10/1/2020

12/31/2020

United States

WTI ¹

Fixed price derivative swap

45,000

$42.77

10/1/2021

12/31/2021

United States

WTI ¹

Fixed price derivative swap

18,000

$43.31

1/1/2021

12/31/2021

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

WTI ¹

Derivative collars

23,000

$62.652

$74.774

1/1/2022

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

Natural Gas

Fixed price forward sales ~~at AECO~~

59196

C$~~2.81~~2.55

10/~~1/2020~~

~~12/31/2020~~

~~Montney~~

~~Natural Gas~~

~~Fixed price forward sales at AECO~~

~~C$2.53~~

1/1/2021

12/31/2021

Montney

Natural Gas

Fixed price forward sales ~~at AECO~~

71186

C$~~2.50~~2.36

1/1/2022

1/31/2022

Montney

Natural Gas

Fixed price forward sales

176

C$2.34

2/1/2022

4/30/2022

Montney

Natural Gas

Fixed price forward sales

205

C$2.34

5/1/2022

5/31/2022

Montney

Natural Gas

Fixed price forward sales

247

C$2.34

6/1/2022

10/31/2022

Montney

Natural Gas

Fixed price forward sales

266

C$2.36

11/1/2022

12/31/2022

Montney

Natural Gas

Fixed price forward sales

269

C$2.35

1/1/2023

3/31/2023

Montney

Natural Gas

Fixed price forward sales

250

C$2.35

4/1/2023

12/31/2023

Montney

Natural Gas

Fixed price forward sales

162

C$2.39

1/1/2024

12/31/2024

Montney

Natural Gas

Fixed price forward sales

US$2.05

10/1/2021

12/31/2022

Montney

Natural Gas

Fixed price forward sales

US$1.98

1/1/2023

10/31/2024

Montney

Natural Gas

Fixed price forward sales

US$1.98

11/1/2024

12/31/2024

Volumes
(MMcf/d) Price
(USD/MMBtu) Remaining Period
Area Commodity Type Start Date End Date
Montney Natural Gas Fixed price forward sales at Malin 20 $2.60 1/1/2021 12/31/2022

~~Table of Contents~~

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

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, ~~“goal”~~“goal��, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s ~~2019~~2020 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 3837 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There were commodity transactions in place at September 30, ~~2020,~~2021, covering certain future U.S. crude oil sales volumes in ~~2020.~~2021 and 2022. A 10% increase in the respective benchmark price of these commodities would have ~~decreased~~increased the net ~~receivable~~payable associated with these derivative contracts by approximately ~~$44.7~~$113.6 million, while a 10% decrease would have ~~increased~~decreased the recorded ~~receivable~~net payable by a similar amount.

There were no derivative foreign exchange contracts in place at September 30, ~~2020.~~2021.

ITEM 4. CONTROLS AND PROCEDURES

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

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

During the quarter ended September 30, ~~2020,~~2021, 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 ~~2019~~2020 Form 10-K filed on February ~~27, 2020.~~26, 2021. The Company has not identified any additional risk factors not previously disclosed in its ~~2019~~2020 Form 10-K ~~report, except as discussed below.~~

~~Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.~~

Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil, natural gas liquids and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:

•the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;

•~~worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;~~

•~~the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;~~

•~~the production levels of non-OPEC countries, including production levels in the shale plays in the United States;~~

•~~the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;~~

•~~political instability or armed conflict in oil and natural gas producing regions;~~

•~~changes in weather patterns and climate;~~

•~~natural disasters such as hurricanes and tornadoes;~~

•~~the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;~~

•~~the effect of conservation efforts;~~

•~~technological advances affecting energy consumption and energy supply;~~

•~~domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and~~

•~~general economic conditions worldwide.~~

The global downturn triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon (most notably oil) energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.

In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day (MMBLD) in May and June 2020. Production cuts of 9.6 MMBLD were extended through the end of July 2020 and cuts of 7.7 MMBLD were made for August and September. OPEC+ are expected to target cuts of 7.7 MMBLD for the remainder of 2020.

For the three months ended September 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $41 per barrel (compared to $46 and $28 and in the first and second quarters of 2020, respectively). The closing price for WTI at the end of the third quarter of 2020 was approximately $40 per barrel (compared to $30 per barrel at the end of the first quarter and $38 at the end of the second quarter), reflecting a 34% reduction from the price at the end of 2019. In comparison, WTI averaged approximately $57 in 2019, $65 in 2018 and $51 in 2017. The closing price for WTI at the end of 2019 was approximately $60 per barrel. As of close on November 4, 2020, the NYMEX WTI forward curve price for 2020 and 2021 were $39.15 and $41.06 per barrel, respectively. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the WTI prices.

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The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended September 30, 2020 was $1.95 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of September 30, 2020, was $1.92 per MMBTU. In comparison, NYMEX natural gas was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017. The closing price for NYMEX natural gas as of December 31, 2019, was $2.19 per MMBTU. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged US$1.33 per MMBTU in 2019 and US$1.61 in 2020, up to the end of the third quarter. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 35 and certain variable netback contracts providing exposure to Malin and Chicago City Gate prices.

Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue for the remainder of 2020 and beyond. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize, which could impact the recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales.

~~See Note L - Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.~~

We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See “Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”

If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.

It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.

We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company has initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.

We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.

~~The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) its joint venture partners and (iii) other counterparties.~~

~~Murphy is exposed to credit risk in three principle areas:~~

•~~Accounts receivable credit risk from selling its produced commodity to customers;~~

•Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and

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•~~Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices~~

~~To mitigate these risks the Company:~~

•~~Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;~~

•Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.

The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.report.

ITEM 6. EXHIBITS

The Exhibit Index on page 4239 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 D. HULSE
						Christopher D. Hulse
						Vice President and Controller
						(Chief Accounting Officer and Duly Authorized Officer)

November ~~5, 2020~~4, 2021

(Date)

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EXHIBIT INDEX

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


Exhibit No.

*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

~~Exhibits other than those listed above have been omitted since they are either not required or not applicable.~~

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	Total Assets at September 30, 2020		Three Months Ended September 30, 2020			Three Months Ended September 30, 2019
(Millions of dollars)			External Revenues		Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States	$	7,028.0	330.8		(172.6)	656.8	170.8
Canada	2,155.5		96.3		(8.6)	95.0	(9.1)
Other	264.1		0		(11.7)	1.9	(3.7)
Total exploration and production	9,447.6		427.1		(192.9)	753.7	158.0
Corporate	1,002.1		(5.2)		(72.9)	63.4	0.3
Assets/revenue/income (loss) from continuing operations	10,449.7		421.9		(265.8)	817.1	158.3
Discontinued operations, net of tax	19.7		0		(0.8)	0	953.4
Total	$	10,469.4	421.9		(266.6)	817.1	1,111.7

			Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
			External Revenues		Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States			$	1,070.6	(1,011.7)	1,734.3	420.0
Canada			245.2		(35.0)	323.8	(7.5)
Other			1.8		(73.0)	7.9	(35.4)
Total exploration and production			1,317.6		(1,119.7)	2,066.0	377.1
Corporate			319.5		26.9	125.6	(97.0)
Assets/revenue/income (loss) from continuing operations			1,637.1		(1,092.8)	2,191.6	280.1
Discontinued operations, net of tax			0		(6.9)	0	1,027.6
Total			$	1,637.1	(1,099.7)	2,191.6	1,307.7


(Thousands of dollars)	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
Severance	$	2,635	22,502
Pension and termination benefit charges	0		10,913
Contract exit costs and other	2,347		12,964
Restructuring charges	$	4,982	46,379