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~~March 31, 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~~April 30, 2021 was ~~153,598,625~~154,399,812.

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			1211
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			1716
Note M – Accumulated Other Comprehensive Loss			18
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			21
~~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			3734
Item 4. Controls and Procedures			3734
Part II – Other Information			3835
Item 1. Legal Proceedings			3835
Item 1A. Risk Factors			3835

Item 6. Exhibits			4035
Signature			4136

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)	March 31, 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	$	230,870	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	278,819		262,014
Inventories	Inventories	67,856		76,123	Inventories	66,585		66,076
Prepaid expenses	Prepaid expenses	58,099		40,896	Prepaid expenses	37,634		33,860
Assets held for sale	Assets held for sale	108,916		123,864	Assets held for sale	77,397		327,736
Total current assets	Total current assets	733,656		974,327	Total current assets	691,305		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 $11,869,715 in 2021 and $11,455,305 in 2020					Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,869,715 in 2021 and $11,455,305 in 2020	8,216,722		8,269,038
Operating lease assets	Operating lease assets	765,484		598,293	Operating lease assets	911,941		927,658
Deferred income taxes	Deferred income taxes	347,053		129,287	Deferred income taxes	433,617		395,253
Deferred charges and other assets	Deferred charges and other assets	30,324		46,854	Deferred charges and other assets	30,759		28,611

Total assets	Total assets	$	10,469,351	11,718,504	Total assets	$	10,284,344	10,620,852
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY				LIABILITIES AND EQUITY
Current liabilities	Current liabilities				Current liabilities

Accounts payable	Accounts payable	$	295,398	602,096	Accounts payable	$	538,327	407,097
Income taxes payable	Income taxes payable	17,813		19,049	Income taxes payable	17,370		18,018
Other taxes payable	Other taxes payable	23,755		18,613	Other taxes payable	18,032		22,498
Operating lease liabilities	Operating lease liabilities	100,169		92,286	Operating lease liabilities	102,983		103,758
Other accrued liabilities	Other accrued liabilities	157,574		197,447	Other accrued liabilities	174,575		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	14,097		14,372
Total current liabilities	Total current liabilities	609,386		942,789	Total current liabilities	865,384		716,321
Long-term debt, including capital lease obligation		2,987,057		2,803,381
Long-term debt					Long-term debt	2,755,596		2,988,067
Asset retirement obligations	Asset retirement obligations	856,856		825,794	Asset retirement obligations	904,085		816,308
Deferred credits and other liabilities	Deferred credits and other liabilities	635,980		613,407	Deferred credits and other liabilities	691,254		680,580
Non-current operating lease liabilities	Non-current operating lease liabilities	686,516		521,324	Non-current operating lease liabilities	829,760		845,088
Deferred income taxes	Deferred income taxes	179,511		207,198	Deferred income taxes	138,656		180,341

Total liabilities	Total liabilities	5,955,306		5,913,893	Total liabilities	6,184,735		6,226,705
Equity	Equity				Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, NaN issued	Cumulative Preferred Stock, par $100, authorized 400,000 shares, NaN issued	0		0	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
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	914,303		941,692
Retained earnings	Retained earnings	5,560,673		6,614,304	Retained earnings	5,062,813		5,369,538
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(657,995)		(574,161)	Accumulated other comprehensive loss	(575,610)		(601,333)
Treasury stock	Treasury stock	(1,690,661)		(1,717,217)	Treasury stock	(1,661,416)		(1,690,661)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	4,343,436		5,467,460	Murphy Shareholders' Equity	3,935,191		4,214,337
Noncontrolling interest	Noncontrolling interest	170,609		337,151	Noncontrolling interest	164,418		179,810
Total equity	Total equity	4,514,045		5,804,611	Total equity	4,099,609		4,394,147
Total liabilities and equity	Total liabilities and equity	$	10,469,351	11,718,504	Total liabilities and equity	$	10,284,344	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 March 31,
(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
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		$	592,527	600,558
(Loss) gain on crude contracts	(Loss) gain on crude contracts	(5,290)		63,247	319,502	121,163	(Loss) gain on crude contracts		(214,385)		400,672
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		1,843		2,498
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		379,985		1,003,728
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		147,164		209,148
Severance and ad valorem taxes	Severance and ad valorem taxes	6,781		13,803	22,645	36,972	Severance and ad valorem taxes		9,231		9,422
Transportation, gathering and processing	Transportation, gathering and processing	41,322		54,305	126,779	128,748	Transportation, gathering and processing		42,912		44,367
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		11,780		20,126
Selling and general expenses	Selling and general expenses	28,509		55,366	104,381	176,258	Selling and general expenses		29,503		36,772
Restructuring expenses		4,982		0	46,379	0

Depreciation, depletion and amortization	Depreciation, depletion and amortization	231,603		325,562	769,151	819,270	Depreciation, depletion and amortization		198,278		306,102
Accretion of asset retirement obligations	Accretion of asset retirement obligations	10,778		10,587	31,213	29,824	Accretion of asset retirement obligations		10,492		9,966
Impairment of assets	Impairment of assets	219,138		0	1,206,284	0	Impairment of assets		171,296		967,530
Other (benefit) expense		20,224		(29,000)	(2,957)	26,442
Other expense (benefit)							Other expense (benefit)		21,079		(45,188)
Total costs and expenses	Total costs and expenses	699,920		590,613	2,843,844	1,709,544	Total costs and expenses		641,735		1,558,245
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 loss from continuing operations							Operating loss from continuing operations		(261,750)		(554,517)
Other income (loss)							Other income (loss)
Interest and other income (loss)							Interest and other income (loss)		(5,341)		241
Interest expense, net	Interest expense, net	(45,182)		(44,930)	(124,877)	(145,095)	Interest expense, net		(88,100)		(41,097)
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		(93,441)		(40,856)
Loss from continuing operations before income taxes							Loss from continuing operations before income taxes		(355,191)		(595,373)
Income tax benefit							Income tax benefit		(88,159)		(91,533)
Loss from continuing operations							Loss from continuing operations		(267,032)		(503,840)
Income (loss) from discontinued operations, net of income taxes							Income (loss) from discontinued operations, net of income taxes		208		(4,862)
Net loss including noncontrolling interest							Net loss including noncontrolling interest		(266,824)		(508,702)
Less: Net income (loss) attributable to noncontrolling interest							Less: Net income (loss) attributable to noncontrolling interest		20,614		(92,598)
NET LOSS ATTRIBUTABLE TO MURPHY							NET LOSS ATTRIBUTABLE TO MURPHY		$	(287,438)	(416,104)
LOSS PER COMMON SHARE – BASIC							LOSS PER COMMON SHARE – BASIC
Continuing operations	Continuing operations	$	(1.58)	0.85	(6.31)	1.16	Continuing operations		$	(1.87)	(2.68)
Discontinued operations	Discontinued operations	(0.01)		5.94	(0.05)	6.14	Discontinued operations		0		(0.03)
Net (loss) income		$	(1.59)	6.79	(6.36)	7.30
(LOSS) INCOME PER COMMON SHARE – DILUTED
Net loss							Net loss		$	(1.87)	(2.71)
LOSS PER COMMON SHARE – DILUTED							LOSS PER COMMON SHARE – DILUTED
Continuing operations	Continuing operations	$	(1.58)	0.84	(6.31)	1.16	Continuing operations		$	(1.87)	(2.68)
Discontinued operations	Discontinued operations	(0.01)		5.92	(0.05)	6.11	Discontinued operations		0		(0.03)
Net (loss) income		$	(1.59)	6.76	(6.36)	7.27
Net loss							Net loss		$	(1.87)	(2.71)
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		0.25

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		153,953		153,313
Diluted	Diluted	153,596		160,980	153,480	168,105	Diluted		153,953		153,313

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 March 31,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)		2021		2020
Net (loss) income including noncontrolling interest	Net (loss) income including noncontrolling interest	$	(266,608)	1,111,702	(1,099,710)	1,307,713	Net (loss) income including noncontrolling interest		$	(266,824)	(508,702)
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		19,897		(118,411)
Retirement and postretirement benefit plans	Retirement and postretirement benefit plans	3,726		2,761	(45,219)	8,277	Retirement and postretirement benefit plans		4,136		(9,711)
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		1,690		299

Other comprehensive (loss) income	Other comprehensive (loss) income	32,346		(13,782)	(83,834)	46,960	Other comprehensive (loss) income		25,723		(127,823)
COMPREHENSIVE (LOSS) INCOME	COMPREHENSIVE (LOSS) INCOME	$	(234,262)	1,097,920	(1,183,544)	1,354,673	COMPREHENSIVE (LOSS) INCOME		$	(241,101)	(636,525)

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


		Nine Months Ended September 30,				Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	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 loss including noncontrolling interest					Net loss including noncontrolling interest	$	(266,824)	(508,702)
Adjustments to reconcile net loss to net cash provided by continuing operations activities					Adjustments to reconcile net loss to net cash provided by continuing operations activities
(Income) loss from discontinued operations					(Income) loss from discontinued operations	(208)		4,862
Depreciation, depletion and amortization	Depreciation, depletion and amortization	769,151		819,270	Depreciation, depletion and amortization	198,278		306,102
Previously suspended exploration costs	Previously suspended exploration costs	8,255		12,901	Previously suspended exploration costs	717		97
Amortization of undeveloped leases	Amortization of undeveloped leases	21,951		21,680	Amortization of undeveloped leases	4,602		7,478
Accretion of asset retirement obligations	Accretion of asset retirement obligations	31,213		29,824	Accretion of asset retirement obligations	10,492		9,966
Impairment of assets	Impairment of assets	1,206,284		0	Impairment of assets	171,296		967,530
Noncash restructuring expense		17,565		0
Deferred income tax (benefit) expense		(231,748)		50,597

Mark to market (gain) loss on contingent consideration		(29,476)		512
Mark to market (gain) loss on crude contracts		(104,463)		(100,076)
Deferred income tax benefit					Deferred income tax benefit	(88,867)		(81,373)

Mark to market loss (gain) on contingent consideration					Mark to market loss (gain) on contingent consideration	14,923		(59,151)
Mark to market loss (gain) on crude contracts					Mark to market loss (gain) on crude contracts	153,505		(358,302)
Long-term non-cash compensation	Long-term non-cash compensation	35,200		60,567	Long-term non-cash compensation	12,124		9,805
Net decrease (increase) in noncash operating working capital		(26,261)		40,257
Net (increase) decrease in noncash working capital					Net (increase) decrease in noncash working capital	(9,052)		107,827
Other operating activities, net	Other operating activities, net	(26,837)		(62,386)	Other operating activities, net	36,780		(13,482)
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	237,766		392,657
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	(240,545)		(354,834)
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)		(21,296)
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	268,023		0
Net cash required by investing activities		(723,661)		(2,203,023)
Net cash provided (required) by investing activities					Net cash provided (required) by investing activities	9,744		(376,130)
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	140,000		170,000
Repayment of revolving credit facility	Repayment of revolving credit facility	(250,000)		(1,900,000)	Repayment of revolving credit facility	(340,000)		0
Retirement of debt					Retirement of debt	(576,358)		(3,570)
Debt issuance, net of cost					Debt issuance, net of cost	541,980		(613)
Early redemption of debt cost					Early redemption of debt cost	(34,177)		0
Distributions to noncontrolling interest					Distributions to noncontrolling interest	(36,006)		(32,399)
Cash dividends paid	Cash dividends paid	(76,790)		(125,437)	Cash dividends paid	(19,287)		(38,392)
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	(3,794)		(7,094)
Debt issuance, net of cost		(613)		0

Capital lease obligation payments	Capital lease obligation payments	(514)		(510)	Capital lease obligation payments	(178)		(168)
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	(327,820)		87,764
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	0		(1,202)
Investing activities	Investing activities	4,494		1,985,202	Investing activities	0		4,494
Financing activities		0		(4,914)

Net cash provided by discontinued operations	Net cash provided by discontinued operations	3,292		2,054,649	Net cash provided by discontinued operations	0		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	574		(3,298)
Net increase (decrease) in cash and cash equivalents		(87,124)		74,976
Net (decrease) increase in cash and cash equivalents					Net (decrease) increase in cash and cash equivalents	(79,736)		100,993
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	$	230,870	407,753

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

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)


		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)		2021		2020
Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued	Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued	$	0	0	0	0	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 at September 30, 2020 and 195,083,364 shares at September 30, 2019
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2021 and 195,083,364 shares at March 31, 2020							Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2021 and 195,083,364 shares at March 31, 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		195,089
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
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		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		(39)		(156)
Restricted stock transactions and other	Restricted stock transactions and other	(409)		—	(33,649)	(38,732)	Restricted stock transactions and other		(33,000)		(32,604)
Share-based compensation	Share-based compensation	5,298		7,365	20,678	25,041	Share-based compensation		5,650		8,245
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		914,303		924,930
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		5,369,538		6,614,304
Net (loss) income for the period	Net (loss) income for the period	(243,553)		1,089,002	(976,841)	1,221,456	Net (loss) income for the period		(287,438)		(416,104)

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		(19,287)		(38,392)
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		5,062,813		6,159,808
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		(601,333)		(574,161)
Foreign currency translation (loss) gain, net of income taxes	Foreign currency translation (loss) gain, net of income taxes	28,323		(17,128)	(39,520)	36,927	Foreign currency translation (loss) gain, net of income taxes		19,897		(118,411)
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		4,136		(9,711)
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		1,690		299

Balance at end of period	Balance at end of period	(657,995)		(562,827)	(657,995)	(562,827)	Balance at end of period		(575,610)		(701,984)
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		(1,690,661)		(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		29,206		25,511
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		39		—
Balance at end of period – 40,784,118 shares of Common Stock in 2021 and 21,456,366 shares of Common Stock in 2020, at cost							Balance at end of period – 40,784,118 shares of Common Stock in 2021 and 21,456,366 shares of Common Stock in 2020, at cost		(1,661,416)		(1,691,706)
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	4,343,436		5,676,650	4,343,436	5,676,650	Murphy Shareholders’ Equity		3,935,191		4,886,149
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		179,810		337,151
Acquisition closing adjustments		—		(3,328)	—	(7,920)

Net (loss) income attributable to noncontrolling interest	Net (loss) income attributable to noncontrolling interest	(23,055)		22,700	(122,869)	86,257	Net (loss) income attributable to noncontrolling interest		20,614		(92,598)
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(11,273)		(28,734)	(43,673)	(97,510)	Distributions to noncontrolling interest owners		(36,006)		(32,399)
Balance at end of period	Balance at end of period	170,609		349,170	170,609	349,170	Balance at end of period		164,418		212,154
Total Equity	Total Equity	$	4,514,045	6,025,820	4,514,045	6,025,820	Total Equity		$	4,099,609	5,098,303

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 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 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,~~March 31, 2021, our maximum exposure to loss was $3.5 million, 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~~March 31, 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,~~March 31, 2021 and 2020, ~~and 2019,~~ 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 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~~period ended ~~September 30, 2020~~March 31, 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, 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.Recent Accounting Pronouncements

None.

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 gas) in select basins around the globe. The Company’s revenue from sales of oil and 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 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 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 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~~period ended ~~September 30,~~March 31, 2021 and 2020, the Company recognized ~~$425.3~~$592.5 million and $1,311.6 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, the Company recognized $750.3 million and $2,060.1$600.6 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 March 31,
(Thousands of dollars)	(Thousands of dollars)		2020		2019	2020	2019	(Thousands of dollars)		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	$	114,490	131,236
		Offshore	216,918		398,518	714,143	1,090,462		Offshore	328,341		346,972
Canada	Canada	Onshore	32,358		31,758	67,268	88,730	Canada	Onshore	29,903		23,383
		Offshore	19,173		28,407	54,864	115,686		Offshore	18,062		24,614
Other	Other		0		1,933	1,806	7,908	Other		0		1,864
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		490,796		528,069

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	7,528		5,503
		Offshore	4,765		8,414	13,255	18,184		Offshore	10,054		5,026
Canada	Canada	Onshore	2,780		2,751	6,090	8,987	Canada	Onshore	3,987		2,034
Total natural gas liquids revenue	Total natural gas liquids revenue		14,311		16,722	35,490	49,668	Total natural gas liquids revenue		21,569		12,563

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	6,443		5,558
		Offshore	9,827		15,879	35,487	29,575		Offshore	22,138		14,995
Canada	Canada	Onshore	41,710		31,757	116,108	109,580	Canada	Onshore	51,581		39,373
Total natural gas revenue	Total natural gas revenue		56,066		53,484	165,772	159,917	Total natural gas revenue		80,162		59,926
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		592,527		600,558

(Loss) gain on crude contracts	(Loss) gain on crude contracts		(5,290)		63,247	319,502	121,163	(Loss) gain on crude contracts		(214,385)		400,672
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		1,843		2,498
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		$	379,985	1,003,728

Contract Balances and Asset Recognition

As of ~~September 30, 2020,~~March 31, 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~~$179.1 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 contracts that have financing components as ~~of September 30, 2020.~~at March 31, 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 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,~~March 31, 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~~March 31, 2021

Approximate Volumes

Location

Commodity

End Date

Description

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 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 Alberta AECO fixed prices

205 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD index fixed pricing

20 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at USD Index pricing

3525 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at Alberta AECO fixed prices

38 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD Index pricing

3031 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at Alberta AECO fixed prices

134 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD index fixed pricing

15 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD Index pricing

49 MMCFD

Canada

NGL

Q3 2023

Contracts to sell natural gas liquids at various CAD pricing

730 BOED

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.

~~At September 30, 2020,~~As of March 31, 2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of ~~$187.9~~$182.4 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~nine-month~~three-month periods ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020.

(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.


(Thousands of dollars)	2021		2020
Beginning balance at January 1	$	181,616	217,326
Additions pending the determination of proved reserves	785		816

Capitalized exploratory well costs charged to expense	0		(39,709)
Balance at March 31	$	182,401	178,433

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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,								March 31,
		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	$	0	0	0	24,637	3	3
One to two years	One to two years	54,334		5	5	63,615	1	1	One to two years	23,514		3	3	31,541	2	2
Two to three years	Two to three years	0		0	0	27,500	1	0	Two to three years	30,562		2	2	0	0	0
Three years or more	Three years or more	125,525		6	0	124,909	5	0	Three years or more	128,325		6	0	122,255	6	0
		$	187,859	12	5	280,735	12	6		$	182,401	11	5	178,433	11	5

Of the ~~$179.9~~$182.4 million of exploratory well costs capitalized more than one year at ~~September 30, 2020, $88.2~~March 31, 2021, $90.6 million is in Vietnam, ~~$46.0~~$45.9 million is in the U.S., ~~$25.3~~$25.7 million is in Brunei, ~~$15.6~~$15.4 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 current status, including agreements with the partners, of operating and production plans.

In the first quarter of 2020, declines in future oil and natural gas prices (principally driven by increased supply from foreign oil producers and reduced demand in response to 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~~$967.5 million to reduce the carrying values to their estimated fair values as of March 31, 2020 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~~three months ended ~~September 30,~~March 31, 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~~


	Three Months Ended March 31,
(Thousands of dollars)	2021		2020
U.S.	$	0	927,821
Canada	171,296		0
Other Foreign	0		39,709

	$	171,296	967,530

Divestments

~~In July 2019,~~On March 17, 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.

~~Table of Contents~~

~~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 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,~~March 31, 2021 and 2020 ~~and 2019~~ were as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
(Thousands of dollars) 2020 2019 2020 2019
Revenues $ 0 972,737 4,074 1,328,110
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
(Loss) income before taxes (778) 955,397 (6,907) 1,085,715
Income tax expense 0 2,029 0 58,083
(Loss) income from discontinued operations $ (778) 953,368 (6,907) 1,027,632

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)


	Three Months Ended March 31,
(Thousands of dollars)		2021		2020
Revenues		$	44	4,073
Costs and expenses


Other costs and expenses (benefits)		(164)		8,935
(Loss) income before taxes		208		(4,862)
Income tax expense		0		0
(Loss) income from discontinued operations		$	208	(4,862)

The following table presents the carrying value of the major categories of assets and liabilities of the 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 held for sale on the Company’s Consolidated Balance Sheets. ~~Subsequent to period end, 1 of the planes has been sold.~~


(Thousands of dollars)	(Thousands of dollars)	September 30, 2020		December 31, 2019	(Thousands of dollars)	March 31, 2021		December 31, 2020
Current assets	Current assets				Current assets
Cash	Cash	$	29,420	25,185	Cash	$	9,469	10,185
Accounts receivable		425		4,834

Inventories	Inventories	406		406	Inventories	193		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	58,294		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		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	$	77,397	327,736

Current liabilities	Current liabilities				Current liabilities
Accounts payable	Accounts payable	$	5,481	3,702	Accounts payable	$	5,213	5,306

Other accrued liabilities					Other accrued liabilities	36		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)	746		737
Taxes payable	Taxes payable	1,510		1,411	Taxes payable	1,510		1,510

Long-term debt (finance lease)	Long-term debt (finance lease)	6,702		7,240	Long-term debt (finance lease)	6,325		6,513
Asset retirement obligation	Asset retirement obligation	256		240	Asset retirement obligation	267		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	$	14,097	14,372

Note F – Financing Arrangements and Debt

As of ~~September 30, 2020,~~March 31, 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,~~March 31, 2021, the Company had ~~$200.0 million~~0 outstanding borrowings under the RCF and ~~$3.7~~$3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At ~~September 30, 2020,~~March 31, 2021, the interest rate in effect on borrowings under the facility was ~~1.84%~~1.78%. At ~~September 30, 2020,~~March 31, 2021, the Company was in compliance with all covenants related to the RCF.

In March 2021, the Company issued $550 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.0 million on the issuance of these new notes. 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 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 the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months ended March 31, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the three months ended March 31, 2021.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 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,				Three Months Ended March 31,
(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	(Increase) decrease in accounts receivable ¹	$	251,706	(128,698)	(Increase) decrease in accounts receivable ¹	$	(16,954)	186,436
Decrease in inventories	Decrease in inventories	4,747		4,398	Decrease in inventories	392		7,553
(Increase) in prepaid expenses	(Increase) in prepaid expenses	(17,400)		(3,745)	(Increase) in prepaid expenses	(3,652)		(10,179)
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	11,810		(76,287)
Increase (decrease) in income taxes payable	Increase (decrease) in income taxes payable	(1,236)		3,078	Increase (decrease) in income taxes payable	(648)		304
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	$	(9,052)	107,827
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	$	720	72
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 $3.3 million in 2021 and $2.4 million in 2020					Interest paid, net of amounts capitalized of $3.3 million in 2021 and $2.4 million in 2020	44,577		42,344

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	$	6,390	280
(Increase) decrease in capital expenditure accrual		74,742		(52,659)
Decrease in capital expenditure accrual					Decrease in capital expenditure accrual	13,617		10,633

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

2 ~~2019 includes asset retirement obligations assumed as part of the LLOG acquisition~~Excludes non-cash capitalized cost offset by impairment of $~~37.3~~74.4 million~~. See Note P.~~ in 2021.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Employee and Retiree Benefit Plans

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

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~~March 31, 2021 and ~~2019.~~2020.


		Three Months Ended September 30,						Three Months Ended March 31,
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021	2020
Service cost	Service cost	$	1,664	2,064	342	421	Service cost	$	1,768	2,166	326	447
Interest cost	Interest cost	4,827		7,151	612	945	Interest cost	4,286		5,791	521	794
Expected return on plan assets	Expected return on plan assets	(5,773)		(6,455)	0	0	Expected return on plan assets	(6,133)		(6,344)	0	0
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	149		248	0	(98)	Amortization of prior service cost (credit)	156		183	0	0
Recognized actuarial loss	Recognized actuarial loss	5,690		3,516	(24)	0	Recognized actuarial loss	5,279		4,269	(7)	0
Net periodic benefit expense	Net periodic benefit expense	$	6,557	6,524	930	1,268	Net periodic benefit expense	$	5,356	6,065	840	1,241

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

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~~three-month period ended ~~September 30, 2020,~~March 31, 2021, the Company made contributions of ~~$27.4~~$10.6 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~~$31.3 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 the replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.

The 2020 Long-Term Plan and the 2018 Long-Term Incentive Plan authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of ~~5,000,000~~5 million 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.

The 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.

During the first ~~nine~~three months of ~~2020,~~2021, the Committee granted ~~999,700~~1,156,800 performance-based RSUs and ~~340,600~~385,600 time-based RSUs to certain employees under the ~~2018~~2020 Long-Term Plan. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was ~~$21.51~~$16.03 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~~$12.30 per unit. Additionally, in February ~~2020,~~2021, the Committee granted ~~1,152,500~~1,022,700 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February ~~2020~~2021 was ~~$21.68.~~$12.30. Also, in February, the Committee granted ~~106,248~~182,652 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 ~~NED Plan.~~Stock Plan for Non-Employee Directors. These units are scheduled to vest on the ~~third~~first anniversary of the date of grant. The estimated fair value of these awards was ~~$22.59~~$13.14 per unit on date of grant.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the ~~nine-month~~three-month period ended ~~September 30, 2020.~~March 31, 2021.

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


		Nine Months Ended September 30,				Three Months Ended March 31,
(Thousands of dollars)	(Thousands of dollars)	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	$	8,196	553
Related income tax benefit recognized in income		2,278		6,204
Related income tax (expense) benefit recognized in income					Related income tax (expense) benefit recognized in income	1,165		(592)

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Earnings ~~per~~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~~March 31, 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 March 31,
(Weighted-average shares)	(Weighted-average shares)	2020	2019	2020	2019	(Weighted-average shares)		2021	2020
Basic method	Basic method	153,596,109	160,365,705	153,479,654	167,310,202	Basic method		153,952,552	153,312,647
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		0	0
Diluted method	Diluted method	153,596,109	160,980,038	153,479,654	168,105,227	Diluted method		153,952,552	153,312,647

1 Due to a net loss recognized by the Company for the three-month ~~and nine-month~~ periods ended ~~September 30, 2020, no~~March 31, 2021, 0 unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				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		1,771,575		2,490,542
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		$	35.62	$	42.58

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes. For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ the Company’s effective income tax rates were as follows:

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


	2021	2020

Three months ended March 31,	24.8%	15.4%

The effective tax rate for the three-month period ended ~~September 30, 2020~~March 31, 2021 was ~~below~~above the U.S. statutory tax rate of 21% primarily due to losses recorded in Canada which has a higher tax rate, exploration expenses in certain foreign jurisdictions in which no income tax benefit is currently available, as well as no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the three-month period ended March 31, 2020 was below the statutory tax rate of 21% due to impairment charges, 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 period ended September 30, 2019 was below the U.S. 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.

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. 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,~~March 31, 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

~~Table of Contents~~

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

~~Note K– Income Taxes~~ ~~(Contd.)~~

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 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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 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 three-month period ended March 31, 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,~~March 31, 2021, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing through December ~~2020~~2021 at an average price of ~~$56.42,~~$42.77, and ~~18,000~~20,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of ~~2021~~2022 at an average price of ~~$43.31.~~$44.88. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.

At ~~September 30, 2019,~~March 31, 2020, the Company had ~~35,000~~45,000 barrels per day in WTI crude oil swap financial contracts maturing through ~~December 2019~~the end of April 2020 at an average price of ~~$60.51 and 35,000~~$56.42, 65,000 barrels per day in WTI crude oil swap ~~financial~~ contracts maturing ~~through December~~in May and June 2020 at an average price of ~~$57.59.~~$47.20, and 45,000 barrels per day in WTI crude oil swap contracts maturing through the end of 2020 at an average price of $56.42.

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 0 foreign currency exchange short-term derivatives outstanding at ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020.

At ~~September 30, 2020~~March 31, 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

March 31, 2021

December 31, 2020

(Thousands of dollars)

Asset (Liability) Derivatives

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

93,774

Accounts payable

(33,364)

Commodity

Accounts payable

Accounts receivable

13,050

Accounts payable

(234,473)

Accounts payable

(89,842)

Deferred credits and other liabilities

(49,034)

Deferred credits and other liabilities

(12,833)

For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2021 and 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)								Gain (Loss)
(Thousands of dollars)	(Thousands of dollars)	Statement of Operations Location		Three Months Ended September 30,				Nine months ended September 30,				(Thousands of dollars)		Statement of Operations Location		Three months ended March 31,
Type of Derivative Contract	Type of Derivative Contract		2020		2019		2020		2019		Type of Derivative Contract					2021	2020
Commodity	Commodity		(Loss) gain on crude contracts		$	(5,290)	63,247		$	319,502		121,163	Commodity		(Loss) gain on crude contracts			$	(214,385)	400,672

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~~three-month period ended ~~September 30, 2020~~March 31, 2021, the Company redeemed all of the remaining notes due 2022 and ~~2019, $1.1 million and $2.2 million, respectively,~~expensed the remainder of the previously deferred loss on the interest rate ~~swaps was charged~~swap of $2.1 million 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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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~~March 31, 2021 and December 31, ~~2019,~~2020, are presented in the following table.


		September 30, 2020					December 31, 2019					March 31, 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	Commodity derivative contracts	$	0	93,774	0	93,774	0	0	0	0	Commodity derivative contracts	$	0	0	0	0	0	13,050	0	13,050
		$	0	93,774	0	93,774	0	0	0	0		$	0	0	0	0	0	13,050	0	13,050

Liabilities:	Liabilities:										Liabilities:
Nonqualified employee savings plans											Nonqualified employee savings plans	$	15,654	0	0	15,654	14,988	0	0	14,988
Commodity derivative contracts	Commodity derivative contracts	$	0	0	0	0	0	33,364	0	33,364	Commodity derivative contracts	0		283,507	0	283,507	0	102,675	0	102,675
Nonqualified employee savings plans		16,169		0	0	16,169	17,035	0	0	17,035
Contingent consideration	Contingent consideration	0		0	117,311	117,311	0	0	146,787	146,787	Contingent consideration	0		0	147,927	147,927	0	0	133,004	133,004
		$	16,169	0	117,311	133,480	17,035	33,364	146,787	197,186		$	15,654	283,507	147,927	431,434	14,988	102,675	133,004	250,667

The fair value of WTI crude 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 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.

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 consideration payable will be due annually in years 2021 to 2026.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were 0 offsetting positions recorded at ~~September 30, 2020~~March 31, 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~~March 31, 2021 and the changes during the ~~nine-month~~three-month period ended ~~September 30, 2020,~~March 31, 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)	(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Deferred Loss on Interest Rate Derivative Hedges		Total	(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Deferred Loss on Interest Rate Derivative Hedges		Total
Balance at December 31, 2019		$	(353,252)	(218,015)		(2,894)		(574,161)
Balance at December 31, 2020									Balance at December 31, 2020	$	(324,011)	(275,632)		(1,690)		(601,333)
Components of other comprehensive income (loss):	Components of other comprehensive income (loss):								Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	Before reclassifications to income and retained earnings	(39,520)		(55,707)		0		(95,227)	Before reclassifications to income and retained earnings	19,897		0		0		19,897
Reclassifications to income	Reclassifications to income	0		10,488	¹	905	²	11,393	Reclassifications to income	0		4,136	¹	1,690	²	5,826
Net other comprehensive income (loss)	Net other comprehensive income (loss)	(39,520)		(45,219)		905		(83,834)	Net other comprehensive income (loss)	19,897		4,136		1,690		25,723
Balance at September 30, 2020		$	(392,772)	(263,234)		(1,989)		(657,995)
Balance at March 31, 2021									Balance at March 31, 2021	$	(304,114)	(271,496)		0		(575,610)

1 Reclassifications before taxes of ~~$13,720~~$5,252 are included in the computation of net periodic benefit expense for the ~~nine-month~~three-month period ended ~~September 30, 2020.~~March 31, 2021. See Note H for additional information. Related income taxes of ~~$3,232~~$1,116 are included in Income tax expense (benefit) for the ~~nine-month~~three-month period ended ~~September 30, 2020.~~March 31, 2021.

2 Reclassifications before taxes of ~~$1,147~~$2,140 are included in Interest expense, net, for the ~~nine-month~~three-month period ended ~~September 30, 2020.~~March 31, 2021. Related income taxes of ~~$242~~$450 are included in Income tax expense (benefit) for the ~~nine-month~~three-month period ended ~~September 30, 2020.~~March 31, 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 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. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable 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 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			Total Assets at March 31, 2021			Three Months Ended March 31, 2021				Three Months Ended March 31, 2020
(Millions of dollars)	(Millions of dollars)			External Revenues		Income (Loss)	External Revenues	Income (Loss)	(Millions of dollars)			External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹	Exploration and production ¹								Exploration and production ¹
United States	United States	$	7,028.0	330.8		(172.6)	656.8	170.8	United States	$	6,737.8		490.3		119.0		511.5		(696.0)
Canada	Canada	2,155.5		96.3		(8.6)	95.0	(9.1)	Canada	2,364.0			104.0		(124.3)		89.7		(6.9)
Other	Other	264.1		0		(11.7)	1.9	(3.7)	Other	264.3			0		(6.9)		1.8		(52.3)
Total exploration and production	Total exploration and production	9,447.6		427.1		(192.9)	753.7	158.0	Total exploration and production	9,366.1			594.3		(12.2)		603.0		(755.2)
Corporate	Corporate	1,002.1		(5.2)		(72.9)	63.4	0.3	Corporate	917.4			(214.3)		(254.8)		400.7		251.4
Assets/revenue/income (loss) from continuing operations	Assets/revenue/income (loss) from continuing operations	10,449.7		421.9		(265.8)	817.1	158.3	Assets/revenue/income (loss) from continuing operations	10,283.5			380.0		(267.0)		1,003.7		(503.8)
Discontinued operations, net of tax	Discontinued operations, net of tax	19.7		0		(0.8)	0	953.4	Discontinued operations, net of tax	0.8			0		0.2		0		(4.9)
Total	Total	$	10,469.4	421.9		(266.6)	817.1	1,111.7	Total	$	10,284.3		380.0		(266.8)		1,003.7		(508.7)

				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.~~25.

Table of Contents

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

~~Note P – Acquisitions~~

~~LLOG Acquisition~~:

In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. 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 in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.

~~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~~

~~Table of Contents~~

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

In ~~2020~~2021, the ~~continued spread~~effects of the ongoing coronavirus disease 2019 (COVID-19) pandemic have been tempered by the global dissemination of several vaccinations. This has led to ~~disruption in the global economy~~a current and ~~a weakness in demand for crude oil. In the first quarter~~expected future recovery of 2020, certain major global suppliers of crude oil announced supply increases which resulted in a contribution to the lower global commodity prices in the first quarter and early second quarter. In early second quarter of 2020, theenergy demand. The OPEC+ group of oil producing countries ~~agreed~~scaled back production cuts marginally by 0.5 MMBOD to ~~supply restrictions which helped support~~7.2 MMBOD in January 2021 and 7.1 MMBOD for February and March. Outside of the OPEC+ agreement, Saudi Arabia unilaterally implemented an additional 1.0 MMBOD cut in February and March 2021. These items combined have supported a higher oil price infor 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 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,~~March 31, 2021, West Texas Intermediate (WTI) crude oil prices averaged approximately ~~$41~~$58 per barrel (compared to ~~$28~~$46 in the ~~second~~first quarter of 2020 and ~~$56 in the third quarter of 2019)~~$39 for 2020 full year). The closing price for WTI at the end of the ~~third~~first quarter of ~~2020~~2021 was approximately ~~$40~~$62 per barrel, reflecting a ~~34% reduction~~32% increase from the price at the end of ~~2019.~~2020. The average price in ~~October 2020~~April 2021 was ~~$39.55~~$61.70 per barrel. As of close on ~~November~~May 4, ~~2020,~~2021, the NYMEX WTI forward curve ~~prices~~price for the remainder of ~~2020~~2021 and ~~2021~~2022 were ~~$39.15~~$64.70 and ~~$41.06~~$60.46 per barrel, respectively.

For the three months ended ~~September 30, 2020,~~March 31, 2021, the Company produced ~~163~~165 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested ~~$122.7~~$251.1 million in capital expenditures (on a value of work done basis) in the ~~third quarter of 2020,~~three months ended March 31, 2021, which included ~~$19.3~~$17.2 million to fund the development of the King’s Quay ~~Floating Production System (FPS)~~FPS (subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of ~~$265.8~~$267.0 million (which includes apost tax impairment charges of $128.0 million and loss attributable to noncontrolling interest of ~~$23.1~~$20.6 million) for the ~~third quarter of 2020.~~three months ended March 31, 2021.

For the ~~nine~~three months ended ~~September 30,~~March 31, 2020, the Company produced ~~180~~199 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested ~~$680.3~~$378.0 million in capital expenditures (on a value of work done basis) for the ~~nine~~three months ended ~~September 30,~~March 31, 2020, which included ~~$80.7~~$28.8 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of ~~$1,092.8~~$503.8 million (which includes ~~impairment charges of $854.2 million, net of tax, and a~~ loss attributable to noncontrolling interest of ~~$122.9 million) for the nine months ended September 30, 2020.~~

For the three months ended September 30, 2019, the Company produced 203 thousand barrels 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) in the third quarter of 2019. The Company reported net income from continuing operations of $158.3 million (which includes income attributable to noncontrolling interest of $22.7$92.6 million) for the three months ended ~~September 30, 2019.~~

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.March 31, 2020.

During the three-month ~~and nine-month~~ periods ended ~~September 30, 2020,~~March 31, 2021, crude oil and condensate volumes from continuing operations were lower than the prior year ~~period~~period. The decrease in production volumes is due to lower capital expenditures throughout 2020 and the first quarter of 2021 to support generating positive free cash flow. Revenue from sales to customers was 1% lower compared to 2020, whilst revenue from commodity price hedges decreased 154%, primarily as a result of ~~lower Eagle Ford Shale volumes (due to lower capital expenditures) and higher hurricane and storm downtime~~increasing oil prices.

In March 2021, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the ~~Gulf~~King’s Quay floating production system (FPS) and associated export lateral pipelines. The transaction reimbursed Murphy for its share of ~~Mexico. Revenue, compared~~project costs from inception to ~~2019, was also impacted by~~closing with proceeds of $267.7 million. Further, in March 2021, the ~~lower average oil prices.~~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 ~~results~~2022 notes were redeemed for total use of funds of $619.5 million, which includes redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and incurred closing costs of $8.0 million (the proceeds from issue are ~~explained in more detail below.~~reported net of costs to issue on the balance sheet).

2322

Table of Contents

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Results of Operations

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


		Income (Loss)							Income (Loss)
		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2020		2019	2020	2019	(Millions of dollars)		2021	2020
Exploration and production	Exploration and production	$	(192.9)	158.0	(1,119.7)	377.1	Exploration and production		(12.2)	(755.2)
Corporate and other	Corporate and other	(72.9)		0.3	26.9	(97.0)	Corporate and other		(254.8)	251.4
(Loss) income from continuing operations	(Loss) income from continuing operations	(265.8)		158.3	(1,092.8)	280.1	(Loss) income from continuing operations		(267.0)	(503.8)
Discontinued operations ¹	Discontinued operations ¹	(0.8)		953.4	(6.9)	1,027.6	Discontinued operations ¹		0.2	(4.9)
Net (loss) income including noncontrolling interest	Net (loss) income including noncontrolling interest	$	(266.6)	1,111.7	(1,099.7)	1,307.7	Net (loss) income including noncontrolling interest		(266.8)	(508.7)

1 The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

Exploration and Production

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


		Income (Loss)							Income (Loss)
		Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
(Millions of dollars)	(Millions of dollars)	2020		2019	2020	2019	(Millions of dollars)		2021	2020
Exploration and production	Exploration and production						Exploration and production
United States	United States	$	(172.6)	170.8	(1,011.7)	420.0	United States		119.0	(696.0)
Canada	Canada	(8.6)		(9.1)	(35.0)	(7.5)	Canada		(124.3)	(6.9)
Other	Other	(11.7)		(3.7)	(73.0)	(35.4)	Other		(6.9)	(52.3)
Total	Total	$	(192.9)	158.0	(1,119.7)	377.1	Total		(12.2)	(755.2)

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 (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 March 31,
(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
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 loss attributable to Murphy (GAAP)							Net loss attributable to Murphy (GAAP)		(287.4)	(416.1)
Income tax benefit							Income tax benefit		(88.2)	(91.5)
Interest expense, net	Interest expense, net	45.2		44.9	124.9	145.1	Interest expense, net		88.1	41.1
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		188.3	286.2
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)		(99.2)	(180.3)
Impairment of assets ¹	Impairment of assets ¹	186.5		—	1,072.5	—	Impairment of assets ¹		171.3	866.4
Mark-to-market loss (gain) on crude oil derivative contracts	Mark-to-market loss (gain) on crude oil derivative contracts	69.3		(49.2)	(104.5)	(100.1)	Mark-to-market loss (gain) on crude oil derivative contracts		153.5	(358.3)
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		14.9	(59.2)
Restructuring expenses		5.0		—	46.4	—
Accretion of asset retirement obligations	Accretion of asset retirement obligations	10.8		10.6	31.2	29.8	Accretion of asset retirement obligations		10.5	10.0
Unutilized rig charges	Unutilized rig charges	5.2		—	13.2	—	Unutilized rig charges		2.8	3.5
Discontinued operations loss (income)		0.8		(953.4)	6.9	(1,027.6)
Foreign exchange losses (gains)							Foreign exchange losses (gains)		1.3	(4.7)
Discontinued operations (income) loss							Discontinued operations (income) loss		(0.2)	4.9
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		(1.7)		(8.0)	(1.7)	(8.0)

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)		254.9	287.1

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)		13,670	17,071

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		18.65	16.82

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

2524

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED ~~SEPTEMBER 30,~~MARCH 31, 2021 AND 2020 ~~AND 2019~~


(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
Three Months Ended March 31, 2021							Three Months Ended March 31, 2021
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	330.8	96.3	—	427.1	Oil and gas sales and other operating revenues	$	490.3	104.0	—	594.3
Lease operating expenses	Lease operating expenses	91.5		32.6	0.4	124.5	Lease operating expenses	116.1		30.8	0.3	147.2
Severance and ad valorem taxes	Severance and ad valorem taxes	6.4		0.3	—	6.7	Severance and ad valorem taxes	8.9		0.3	—	9.2
Transportation, gathering and processing	Transportation, gathering and processing	29.3		12.0	—	41.3	Transportation, gathering and processing	28.5		14.4	—	42.9
Depreciation, depletion and amortization	Depreciation, depletion and amortization	166.2		59.6	0.5	226.3	Depreciation, depletion and amortization	149.6		44.8	0.5	194.9
Impairments of assets		205.1		—	—	205.1
Impairment of assets							Impairment of assets	—		171.3	—	171.3
Accretion of asset retirement obligations	Accretion of asset retirement obligations	9.4		1.4	—	10.8	Accretion of asset retirement obligations	9.0		1.5	—	10.5
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	0.6		—	—	0.6	Dry holes and previously suspended exploration costs	0.7		—	—	0.7
Geological and geophysical	Geological and geophysical	0.1		—	(0.1)	—	Geological and geophysical	0.6		—	0.2	0.8
Other exploration	Other exploration	0.6		0.1	3.6	4.3	Other exploration	0.6		—	5.0	5.6
		1.3		0.1	3.5	4.9		1.9		—	5.2	7.1
Undeveloped lease amortization	Undeveloped lease amortization	4.9		0.1	2.3	7.3	Undeveloped lease amortization	2.3		0.1	2.2	4.6
Total exploration expenses	Total exploration expenses	6.2		0.2	5.8	12.2	Total exploration expenses	4.2		0.1	7.4	11.7
Selling and general expenses	Selling and general expenses	5.3		3.4	1.6	10.3	Selling and general expenses	5.5		4.1	1.4	11.0
Other	Other	22.5		(1.5)	2.5	23.5	Other	21.5		3.1	(3.5)	21.1
Results of operations before taxes	Results of operations before taxes	(211.1)		(11.7)	(10.8)	(233.6)	Results of operations before taxes	147.0		(166.4)	(6.1)	(25.5)
Income tax provisions (benefits)	Income tax provisions (benefits)	(38.5)		(3.1)	0.9	(40.7)	Income tax provisions (benefits)	28.0		(42.1)	0.8	(13.3)
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	(172.6)	(8.6)	(11.7)	(192.9)	Results of operations (excluding Corporate segment)	$	119.0	(124.3)	(6.9)	(12.2)

Three Months Ended September 30, 2019
Three months ended March 31, 2020							Three months ended March 31, 2020
Oil and gas sales and other operating revenues	Oil and gas sales and other operating revenues	$	656.8	95.0	1.9	753.7	Oil and gas sales and other operating revenues	$	511.5	89.7	1.8	603.0
Lease operating expenses	Lease operating expenses	116.2		31.2	0.2	147.6	Lease operating expenses	178.2		30.6	0.3	209.1
Severance and ad valorem taxes	Severance and ad valorem taxes	13.4		0.4	—	13.8	Severance and ad valorem taxes	9.1		0.3	—	9.4
Transportation, gathering and processing	Transportation, gathering and processing	44.1		10.2	—	54.3	Transportation, gathering and processing	34.6		9.8	—	44.4
Depreciation, depletion and amortization	Depreciation, depletion and amortization	253.5		65.3	0.6	319.4	Depreciation, depletion and amortization	247.5		52.0	0.5	300.0
Impairment of assets							Impairment of assets	927.8		—	39.7	967.5
Accretion of asset retirement obligations	Accretion of asset retirement obligations	9.0		1.6	—	10.6	Accretion of asset retirement obligations	8.6		1.4	—	10.0
Exploration expenses	Exploration expenses						Exploration expenses
Dry holes and previously suspended exploration costs	Dry holes and previously suspended exploration costs	(0.1)		—	—	(0.1)	Dry holes and previously suspended exploration costs	0.1		—	—	0.1
Geological and geophysical	Geological and geophysical	0.2		—	0.2	0.4	Geological and geophysical	1.3		—	3.7	5.0
Other exploration	Other exploration	1.5		0.1	3.8	5.4	Other exploration	0.8		0.2	6.5	7.5
		1.6		0.1	4.0	5.7		2.2		0.2	10.2	12.6
Undeveloped lease amortization	Undeveloped lease amortization	5.2		0.3	1.0	6.5	Undeveloped lease amortization	5.1		0.2	2.2	7.5
Total exploration expenses	Total exploration expenses	6.8		0.4	5.0	12.2	Total exploration expenses	7.3		0.4	12.4	20.1
Selling and general expenses	Selling and general expenses	22.7		7.6	5.6	35.9	Selling and general expenses	3.7		4.4	1.6	9.7
Other	Other	(21.0)		(7.3)	0.5	(27.8)	Other	(45.7)		0.2	(1.2)	(46.7)
Results of operations before taxes	Results of operations before taxes	212.1		(14.4)	(10.0)	187.7	Results of operations before taxes	(859.6)		(9.4)	(51.5)	(920.5)
Income tax provisions (benefits)	Income tax provisions (benefits)	41.3		(5.3)	(6.3)	29.7	Income tax provisions (benefits)	(163.6)		(2.5)	0.8	(165.3)
Results of operations (excluding Corporate segment)	Results of operations (excluding Corporate segment)	$	170.8	(9.1)	(3.7)	158.0	Results of operations (excluding Corporate segment)	$	(696.0)	(6.9)	(52.3)	(755.2)

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

Table of Contents

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

Results of Operations (contd.)

Exploration and Production

First quarter 2021 vs. 2020

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

United States E&P operations reported earnings of $119.0 million in the first three months of 2021 compared to a loss of $696.0 million in the first three months of 2020. Results were $815 million favorable in the 2021 quarter compared to the 2020 period primarily due to no impairment charge (for the United States) in the current period (2020: $927.8 million). Further, the change year over year is driven by lower depreciation, depletion and amortization (DD&A: $97.9 million), lower lease operating expenses (LOE: $62.1 million) and lower transportation, gathering, and processing charges ($6.1 million), partially offset by higher income tax expense ($191.6 million), higher other operating expense ($67.2 million), lower revenues ($21.2 million), and higher G&A ($1.8 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of decreased oil demand and abundant oil supply at the time of the assessment. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower revenues were primarily due to lower sales volumes in the U.S., following temporary operational issues at the Cascade & Chinook and Kodiak fields in the Gulf of Mexico (these operational issues are now resolved) and lower Eagle Ford Shale volumes following lower capital expenditures throughout 2020 and the effects of a winter storm. Lower lease operating expenses were primarily due to higher Gulf of Mexico workover costs in the prior year at the Cascade asset. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price and lower DD&A and LOE. Higher other operating expense is primarily due to a unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($14.9 million).

Canadian E&P operations reported a loss of $124.3 million in the first three months of 2021 compared to a loss of $6.9 million in the first three months quarter of 2020. Results were $117.4 million unfavorable compared to the 2020 period primarily due to an impairment charge ($171.3 million) in the current period, partially offset by higher income tax benefit ($39.6 million), higher revenue ($14.3 million) and lower DD&A ($7.2 million). The impairment charge in the current year is due to the current status, including agreements with the partners, of operating and production plans at Terra Nova. The operator and joint venture partners continue to evaluate options that could support a long-term production plan for Terra Nova. Higher income tax benefit is a result of a pre-tax loss driven by the impairment charge. Higher revenues were primarily attributable to higher prices (oil and condensate, natural gas and NGLs) versus the prior year. Lower lease operating expenses and lower DD&A were a result of lower sales volume following reduced capital expenditures throughout 2020.

Other international E&P operations reported a loss from continuing operations of $6.9 million in the first three months of 2021 compared to a loss of $52.3 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.

Corporate

First quarter 2021 vs. 2020

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on commodity contracts (typically forward swaps to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $254.8 million in the first three months of 2021 compared to earnings of $251.4 million in the first three months of 2020. The $506.2 million unfavorable variance is primarily due to realized and unrealized losses on forward swap commodity contracts in 2021 compared to gains in 2020 (2021: $214.4 million loss; 2020: $400.7 million gain), and higher interest expense ($46.5 million), partially offset by higher tax benefits ($148.7 million), lower G&A ($8.5 million) and lower DD&A ($2.6 million). Realized and unrealized losses in the quarter on forward swap commodity contracts are due to higher market (West Texas Intermediate) prices whereby the contract provides the Company with a fixed price. Interest charges are higher primarily 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 loss driven by the higher realized and unrealized losses on forward swap commodity contracts. As of March 31, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $58.28 and for 2022 was $54.63 (versus fixed hedge prices of $42.77 and $44.88; see below).

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.~~

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~Exploration and Production~~

~~Third quarter 2020 vs. 2019~~

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

United States E&P operations reported a loss of $172.6 million in the third quarter of 2020 compared to income of $170.8 million in the third quarter of 2019. Results were $343.4 million unfavorable in the 2020 quarter compared to the 2019 period 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 volumes in the U.S. Gulf of Mexico (as a result of shut-ins due 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 a result of lower commodity prices and lower capital expenditure plans, was written down to its expected future value. Lower depreciation expense was primarily due to lower depreciation rates following the impairment charges incurred in the first quarter of 2020 and lower sales volume. Lower lease operating expense was primarily attributable to wells being shut-in in the Gulf of Mexico and certain cost-savings initiatives taken across all businesses. Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).

Canadian E&P operations reported a loss of $8.6 million in the third quarter 2020 compared to a loss of $9.1 million in the 2019 quarter. Results were favorable $0.5 million compared to the 2019 period primarily due to higher revenue ($1.3 million), lower depreciation and amortization ($5.7 million), higher tax benefit ($2.2 million), partially offset by lower other operating income ($5.8 million), higher transportation, gathering, and processing expenses ($1.8 million), and higher lease operating expenses ($1.4 million). Higher revenue is primarily attributable to higher gas prices at Tupper, Kaybob, and Placid (higher AECO prices in the quarter). Lower depreciation expense is due to lower production volumes at Tupper and Terra-Nova (shut-in starting in December 2019). Terra Nova is expected to be shut-in for the remainder of 2020 for Asset Integrity work.

Other international E&P operations reported a loss from continuing operations 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. The result was $8.0 million unfavorable in the 2020 period versus 2019 primarily due higher prior period revenue in Brunei and a prior year income tax credit related to Vietnam exploration spend.

~~Nine months 2020 vs.2019~~

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

United States E&P operations reported 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. Results were $1,431.7 million unfavorable in the 2020 period compared to the 2019 period primarily due to an impairment charge ($1,152.5 million), lower revenues ($663.7 million), higher lease operating expenses ($78.2 million), partially offset by lower income tax expense ($337.7 million), 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 million). The impairment charge is primarily the result of lower forecast future prices, as a result of decreased oil demand and increased oil supply (as discussed above). Based on an evaluation of expected future cash flows from properties as 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 recorded in the future. Lower revenues were primarily due to lower commodity prices year over year and lower volumes 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 at Cascade ($51.3 million) and Dalmatian ($20.5 million). Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration (as a result of lower 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).

Canadian E&P operations reported a loss of $35.0 million in the first nine months of 2020 compared to a loss of $7.5 million in the first nine months of 2019. Results were unfavorable $27.5 million compared to the 2019 period primarily due to lower revenue ($78.6 million), partially offset by lower lease operating expense ($16.5 million), lower DD&A ($20.3 million), and lower income tax charges ($15.7 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue through 2020 full year). Lower lease operating expenses and lower DD&A were a result of lower sales.

~~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~~First quarter ~~2020~~2021 vs. ~~2019~~2020

Total hydrocarbon production from continuing operations averaged ~~162,824~~165,382 barrels of oil equivalent per day in the ~~third~~first quarter of ~~2020,~~2021, which represented a ~~20%~~17% decrease from the ~~203,035~~199,194 barrels per day produced in ~~third~~first quarter ~~2019.~~2020. The decrease ~~was~~in production volumes is principally due to ~~GOM shut-in production due~~lower capital expenditures throughout 2020 and the first quarter of 2021 to ~~hurricanes (14.2 MBOED) and lower Eagle Ford Shale production (16.2 MBOED, as a result of lower capex spend at this property).~~support generating positive free cashflow.

Average crude oil and condensate production from continuing operations was ~~95,391~~97,475 barrels per day in the ~~third~~first quarter of ~~2020~~2021 compared to ~~122,950~~122,078 barrels per day in the ~~third~~first quarter of ~~2019.~~2020. The decrease of ~~27,559~~24,603 barrels per day was ~~principally due to~~associated with lower Eagle Ford Shale production (8,868 barrels per day) due to lower capital expenditures ~~(15,731~~and a winter storm resulting in shut-in production (2,250 barrels per day) ~~and lower~~. Lower volumes in the Gulf of Mexico ~~(14,066~~(14,367 barrels per day) are principally due to ~~GOM shut-in production due to hurricanes (11.1 MBOED)~~temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$39.79~~$58.08 per barrel in the ~~third~~first quarter ~~2020~~2021 compared to ~~$59.47~~$46.66 per barrel in the ~~2019~~2020 period, ~~a decrease~~an increase of ~~33%~~24% quarter over quarter.

Total production of natural gas liquids (NGL) from continuing operations was ~~10,523~~9,845 barrels per day in the ~~third~~first quarter ~~2020~~2021 compared to ~~13,601~~13,656 barrels per day in the ~~2019~~2020 period. The average sales price for U.S. NGL was ~~$14.78~~$22.68 per barrel in the ~~2020~~2021 quarter compared to ~~$13.26~~$9.44 per barrel in ~~2019.~~2020. The average sales price for NGL in Canada was ~~$19.97~~$35.92 per barrel in the ~~2020~~2021 quarter compared to ~~$21.03~~$15.96 per barrel in ~~2019.~~2020. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.

Natural gas ~~sales~~production volumes from continuing operations averaged ~~341~~348 million cubic feet per day (MMCFD) in the ~~third~~first quarter ~~2020~~2021 compared to ~~399~~381 MMCFD in ~~2019.~~2020. The decrease of 5732 MMCFD was a result of lower volumes in Canada (13 MMCFD), in the Gulf of Mexico ~~(20~~(9 MMCFD) and ~~lower volumes~~ in ~~Canada (36~~the Eagle Ford Shale (10 MMCFD). Lower volumes in the Gulf of Mexico are principally due to ~~GOM shut-in production due to hurricanes.~~temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). Lower volumes in Canada and Eagle Ford Shale are due to normal well decline and ~~no additional wells in third quarter~~lower capital expenditures throughout 2020 and the effects of ~~2020.~~a winter storm impacting the Eagle Ford Shale.

Natural gas prices for the total Company averaged ~~$1.78~~$2.56 per thousand cubic feet (MCF) in the ~~2020~~2021 quarter, versus ~~$1.46~~$1.73 per MCF average in the same quarter of ~~2019.~~2020. Average natural gas prices in the US and Canada in the quarter were ~~$1.94~~$3.35 and ~~$1.74 respectively.~~

~~Nine months 2020 vs. 2019~~

Total hydrocarbon production from all E&P continuing operations averaged 180,443 barrels of oil equivalent per day in the first nine months of 2020, which represented a 1% increase from the 178,658 barrels per day produced in the first nine months of 2019. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Average crude oil and condensate production from continuing operations was 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. The decrease of 2,084 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 barrels per day) due to the acquisition of assets as part of the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $36.88 per barrel in the first nine months of 2020 compared to $60.94 per barrel in the 2019 period, a decrease of 39% year over year.

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

Natural gas sales volumes from continuing operations averaged 359 million cubic feet per day (MMCFD) in the first nine months of 2020 compared to 341 MMCFD in 2019. The increase of 18 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (24 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the LLOG transaction.

Natural gas prices for the total Company averaged $1.68 per thousand cubic feet (MCF) in the first nine months of 2020, versus $1.72 per MCF average in the same period of 2019. Average natural gas prices in the US and Canada in the quarter were $1.87 and $1.62,$2.26 respectively.

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

3027

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~~March 31, 2021 and ~~2019.~~2020.


			Three Months Ended September 30,		Nine Months Ended September 30,				Three Months Ended March 31,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted		2020	2019	2020	2019	Barrels per day unless otherwise noted			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		22,165	31,033
		Gulf of Mexico 1	56,517	70,583	67,377	64,266		Gulf of Mexico 1		64,363	78,730
Canada	Canada	Onshore	9,595	7,101	8,106	6,503	Canada	Onshore		6,288	6,833
		Offshore	4,428	4,333	5,136	6,302		Offshore		4,589	5,138
Other	Other		—	351	114	435	Other			70	344
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			97,475	122,078
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		3,933	5,585
		Gulf of Mexico 1	3,521	6,597	5,131	4,172		Gulf of Mexico 1		4,679	6,670
Canada	Canada	Onshore	1,513	1,422	1,311	1,197	Canada	Onshore		1,233	1,401
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			9,845	13,656
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		22,016	31,962
		Gulf of Mexico 1	53,046	72,897	67,850	44,029		Gulf of Mexico 1		72,658	81,950
Canada	Canada	Onshore	260,895	296,883	262,279	267,205	Canada	Onshore		253,697	266,848
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			348,371	380,760
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			165,382	199,194
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			(9,174)	(12,020)
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			(354)	(559)
Net natural gas – thousands of cubic feet per day	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			(4,159)	(5,091)
Total noncontrolling interest	Total noncontrolling interest		(10,170)	(11,367)	(11,807)	(12,367)	Total noncontrolling interest			(10,221)	(13,428)
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			155,161	185,767
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.

3128

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~~March 31, 2021 and ~~2019.~~2020.


			Three Months Ended September 30,		Nine Months Ended September 30,				Three Months Ended March 31,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted		2020	2019	2020	2019	Barrels per day unless otherwise noted			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		22,165	31,033
		Gulf of Mexico 1	57,756	71,380	68,436	64,532		Gulf of Mexico 1		62,066	81,002
Canada	Canada	Onshore	9,595	7,101	8,106	6,503	Canada	Onshore		6,288	6,833
		Offshore	4,757	4,945	5,290	6,523		Offshore		3,379	5,175
Other	Other		—	309	104	415	Other			—	313
Total net crude oil and condensate - continuing operations	Total net crude oil and condensate - continuing operations		96,959	124,317	109,881	111,229	Total net crude oil and condensate - continuing operations			93,898	124,356
Net natural gas liquids	Net natural gas liquids						Net natural gas liquids
United States	United States	Onshore	5,489	5,582	5,459	5,622	United States	Onshore		3,933	5,585
		Gulf of Mexico 1	3,521	6,597	5,131	4,172		Gulf of Mexico 1		4,679	6,670
Canada	Canada	Onshore	1,513	1,422	1,311	1,197	Canada	Onshore		1,233	1,401
Total net natural gas liquids - continuing operations	Total net natural gas liquids - continuing operations		10,523	13,601	11,901	10,991	Total net natural gas liquids - continuing operations			9,845	13,656
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		22,016	31,962
		Gulf of Mexico 1	53,046	72,897	67,850	44,029		Gulf of Mexico 1		72,658	81,950
Canada	Canada	Onshore	260,895	296,882	262,279	267,205	Canada	Onshore		253,697	266,848
Total net natural gas - continuing operations	Total net natural gas - continuing operations		341,461	398,901	359,183	341,437	Total net natural gas - continuing operations			348,371	380,760
Total net hydrocarbons - continuing operations including NCI 2,3	Total net hydrocarbons - continuing operations including NCI 2,3		164,392	204,402	181,646	179,126	Total net hydrocarbons - continuing operations including NCI 2,3			161,805	201,472
Noncontrolling interest	Noncontrolling interest						Noncontrolling interest
Net crude oil and condensate – barrels per day	Net crude oil and condensate – barrels per day		(9,545)	(10,481)	(10,886)	(11,269)	Net crude oil and condensate – barrels per day			(8,868)	(12,475)
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			(354)	(559)
Net natural gas – thousands of cubic feet per day 2	Net natural gas – thousands of cubic feet per day 2		(3,269)	(3,403)	(4,137)	(3,933)	Net natural gas – thousands of cubic feet per day 2			(4,159)	(5,091)
Total noncontrolling interest	Total noncontrolling interest		(10,417)	(11,526)	(12,019)	(12,421)	Total noncontrolling interest			(9,915)	(13,883)
Total net hydrocarbons - continuing operations excluding NCI 2,3	Total net hydrocarbons - continuing operations excluding NCI 2,3		153,975	192,875	169,627	166,706	Total net hydrocarbons - continuing operations excluding NCI 2,3			151,890	187,590

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.

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~~March 31, 2021 and ~~2019.~~2020.໿ Comparative periods are conformed to current presentation.


			Three Months Ended September 30,			Nine Months Ended September 30,				Three Months Ended March 31,
			2020		2019	2020	2019				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		57.41	46.46
		Gulf of Mexico 1	40.82		60.69	38.08	61.90		Gulf of Mexico 1		58.78	47.07
Canada 2	Canada 2	Onshore	36.65		48.61	30.29	49.98	Canada 2	Onshore		52.84	37.61
		Offshore	43.81		62.44	37.85	64.97		Offshore		59.39	57.27
Other	Other		—		67.96	63.51	69.86	Other			—	65.55
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		21.25	10.79
		Gulf of Mexico 1	14.71		13.86	9.43	15.96		Gulf of Mexico 1		23.87	8.28
Canada 2	Canada 2	Onshore	19.97		21.03	16.95	27.50	Canada 2	Onshore		35.92	15.96
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		3.27	1.85
		Gulf of Mexico 1	2.01		2.37	1.91	2.46		Gulf of Mexico 1		3.39	2.01
Canada 2	Canada 2	Onshore	1.74		1.16	1.62	1.50	Canada 2	Onshore		2.26	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~~$237.8 million for the first ~~nine~~three months of ~~2020~~2021 compared to ~~$1,153.2~~$392.7 million during the same period in ~~2019.~~2020. The decreased cash from operating activities is primarily attributable to lower revenue from sales to customers ($~~748.5~~8.0 million) and higher ~~lease operating expenses ($61.8 million), partially offset by higher~~ cash payments ~~received~~made on forward swap commodity contracts (2021: realized loss of $60.9 million; 2020: realized gain of $42.4 million), offset by lower lease operating expense ($~~194.0~~62.0 million) and lower general and administrative ~~expenses~~expense ($~~71.9~~7.3 million). ~~See above for explanation of underlying business reasons.~~For the three months ended March 31, 2021, realized losses on crude oil derivative contracts were $60.9 million (pre-tax) and $48.1 million (post-tax.)

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

Cash ~~required~~provided by ~~property~~investing activities was $9.7 million for the first three months of 2021 compared to $376.1 million cash used in the first three months of 2020. On March 17, 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company for previously incurred capital expenditures. Property additions and dry ~~holes,~~hole costs, which includes amounts expensed, were ~~$723.7~~$258.3 million and ~~$2,203.0~~$376.1 million in the ~~nine-month periods ended September 30,~~first three months of 2021 and 2020, respectively. These amounts include $17.7 million and ~~2019, respectively. In 2020, property additions include $74.9~~$21.3 million used to fund the development of the King’s Quay FPS ~~which is expected to be refunded on~~in the ~~closing~~first three months of ~~a transaction to sell this asset to a third party. In 2019, property additions included the LLOG acquisition.~~2021 and 2020, respectively. Lower property additions in ~~2020~~2021 are ~~a result of~~principally due to lower capital spending at Eagle Ford Shale to support generating positive free cashflow. See Outlook section on page 32 for further details.

3330

Table of Contents

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,				Three Months Ended March 31,
(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	$	247.3	374.5
Corporate	Corporate	9.3		8.5	Corporate	3.8		3.5
Total capital expenditures	Total capital expenditures	$	680.3	2,329.1	Total capital expenditures	$	251.1	378.0

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


		Nine Months Ended September 30,				Three Months Ended March 31,
(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	$	240.5	354.8
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		21.3
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	5.8		11.6
Capital expenditure accrual changes and other	Capital expenditure accrual changes and other	(70.2)		57.1	Capital expenditure accrual changes and other	(13.0)		(9.7)
Total capital expenditures	Total capital expenditures	$	680.3	2,329.1	Total capital expenditures	$	251.1	378.0

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 to support generating positive free cash flow, primarily 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.~~

Cash Used in/ Provided by Financing Activities

Net cash used in financing activities was $327.8 million for the first three months of 2021 compared to net cash provided by financing activities ~~was $59.1 million for the first nine months~~ of ~~2020 compared to net cash required by financing activities of $961.4~~$87.8 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 ($576.4 million), early redemption cost of the notes due 2022 ($34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($36.0 million), and cash dividends to shareholders ($19.3 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).

As of March 31, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,596.2 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 the end of the third quarter 2020). In 2019, the cash required~~170.0 million), offset by financing activities was principally from borrowings on our revolver and short-term loan ($1,575.0 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~~($38.4 million), 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.NCI ($32.4 million).

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at ~~September 30, 2020~~March 31, 2021 was ~~$30.0~~a deficit of $237.4 million, ~~$109.1~~$208.0 million ~~higher~~lower than December 31, ~~2019,~~2020, with the ~~increase~~decrease primarily attributable to ~~lower~~higher accounts payable ~~$306.7 million and lower~~($131.2 million), higher other accrued liabilities ~~$39.9 million,~~($24.0 million), partly offset by a lower cash balance ($~~87.1~~79.7 million) and ~~lower~~higher accounts receivable ($~~147.5~~16.8 million). ~~Lower~~Higher accounts payable is primarily due to ~~lower capital activity. Lower accounts receivable is due to lower commodity sales prices.~~the increase in unrealized losses on crude contracts maturing in the next 12 months.

Capital Employed

At ~~September 30, 2020,~~March 31, 2021, long-term debt of ~~$2,987.1~~$2,755.6 million had ~~increased~~decreased by ~~$183.7~~$232.5 million compared to December 31, ~~2019,~~2020, as a result of ~~net borrowing~~repayment of the borrowings on the ~~RCF.~~RCF ($200.0 million) and the redemption of the notes due 2022 ($576.4 million) in excess of the issuance of notes due 2028 ($550.0 million). The fixed-rate notes had a weighted average maturity of ~~7.0~~7.7 years and a weighted average coupon of ~~5.9~~6.3 percent.

3431

Table of Contents

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

Financial Condition (contd.)

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


		September 30, 2020				December 31, 2019					March 31, 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	$	2,755.6	41.2	%	$	2,988.1	41.5	%
Murphy shareholders' equity	Murphy shareholders' equity	4,343.4		59.3	%	5,467.5		66.1	%	Murphy shareholders' equity	3,935.2		58.8	%	4,214.3		58.5	%
Total capital employed	Total capital employed	$	7,330.5	100.0	%	$	8,270.8	100.0	%	Total capital employed	$	6,690.8	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,~~March 31, 2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$56.6~~$59.8 million in Canada. In addition, ~~$18.4 million of cash was held in the United Kingdom and $11.0~~$9.5 million was held in Brunei ~~(both of which were~~(which is reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at ~~September 30, 2020)~~March 31, 2021). 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

Outlook

As discussed in the Summary section on page ~~23,~~22, average crude oil prices ~~recovered~~continued to recover during the ~~third~~first quarter of 2021 versus the first quarter of 2020 ~~from the low seen in the second quarter of 2020.~~(Q1 2020 WTI: $46.17; Q1 2021 WTI: $57.84). As of close on ~~November~~May 4, ~~2020,~~2021, the NYMEX WTI forward curve ~~prices~~price for the remainder of ~~2020~~2021 and ~~2021~~2022 were ~~$39.15~~$64.70 and ~~$41.06~~$60.46 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 ~~pandemic and other economic factors~~pandemic) 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~~second quarter, production is expected to average between ~~146~~160 and ~~154~~168 MBOEPD, excluding NCI. ~~If price volatility persists, the Company~~

The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $725.0 million. Capital and other expenditures will ~~review the option of production curtailments to avoid incurring losses on certain produced barrels.~~

~~In response to the COVID-19 pandemic~~be routinely reviewed during 2021 and ~~reduced commodity prices, the Company reduced 2020~~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 iscontinues to closely ~~monitoring~~monitor the impact of lower commodity prices in 2020 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 and acceptance of the vaccinations which has positively impacted current and expected future energy demand for the next year compared to one year ago.

As of ~~November~~May 4, ~~2020,~~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

4/1/2021

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

1 West Texas Intermediate

Volumes
(MMcf/d)

Price
(CAD/Mcf)

Remaining Period

Area

Commodity

Type

Start Date

End Date

Montney

Natural Gas

Fixed price forward sales at AECO

59203

C$~~2.81~~2.55

~~10/~~4/1/~~2020~~2021

~~12/~~5/31/~~2020~~2021

Montney

Natural Gas

Fixed price forward sales at AECO

96241

C$~~2.53~~2.57

1/6/1/2021

12/31/2021

Montney

Natural Gas

Fixed price forward sales at AECO

71231

C$~~2.50~~2.42

1/1/2022

1/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

221

C$2.41

2/1/2022

4/30/2022

Montney

Natural Gas

Fixed price forward sales at AECO

250

C$2.40

5/1/2022

5/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

292

C$2.39

6/1/2022

12/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

201

C$2.36

1/1/2023

12/31/2023

Montney

Natural Gas

Fixed price forward sales at AECO

147

C$2.41

1/1/2024

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

3532

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”, “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 3835 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

3633

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,~~March 31, 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~~$111.3 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.~~March 31, 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,~~March 31, 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.

3734

Table of Contents

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and 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.

~~Table of Contents~~

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

~~Table of Contents~~

•~~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 4237 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

4035

Table of Contents

SIGNATURE

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


			MURPHY OIL CORPORATION
			(Registrant)

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

~~November 5, 2020~~May 6, 2021

(Date)

4136

Table of Contents

EXHIBIT INDEX


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.

4237


(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