UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

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


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

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

71-0361522

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification Number)

9805 Katy Fwy, Suite G-200

77024

Houston,

Texas

(Zip Code)

(Address of principal executive offices)

(281)

675-9000

(Registrant’s telephone number, including area code)

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


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

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at July 31, ~~2020~~2021 was ~~153,598,625~~154,434,953.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


			Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets			2
Consolidated Statements of Operations			3
Consolidated Statements of Comprehensive Income			4
Consolidated Statements of Cash Flows			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Note A – Nature of Business and Interim Financial Statements			7
Note B – New Accounting Principles and Recent Accounting Pronouncements			7
Note C – Revenue from Contracts with Customers			8
Note D – Property, Plant, and Equipment			10
Note E – Discontinued Operations and Assets Held for Sale			12
Note F – Financing Arrangements and Debt			12
Note G – Other Financial Information			13
Note H – Employee and Retiree Benefit Plans			14
Note I – Incentive Plans			1514
Note J – Earnings Per Share			16
Note K – Income Taxes			16
Note L – Financial Instruments and Risk Management			17
Note M – Accumulated Other Comprehensive Loss			1819
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			2120
Note P – ~~Acquisitions~~Leases			2221
~~Note Q – Restructuring Charges~~			22

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2423




Item 3. Quantitative and Qualitative Disclosures About Market Risk			3836
Item 4. Controls and Procedures			3836
Part II – Other Information			3937
Item 1. Legal Proceedings			3937
Item 1A. Risk Factors			3937
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 6. Exhibits			4137
Signature			4238

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)


(Thousands of dollars)	(Thousands of dollars)	June 30, 2020		December 31, 2019	(Thousands of dollars)	June 30, 2021		December 31, 2020
ASSETS	ASSETS				ASSETS
Current assets	Current assets				Current assets
Cash and cash equivalents	Cash and cash equivalents	$	145,505	306,760	Cash and cash equivalents	$	418,100	310,606
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019		372,549		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	366,542		262,014
Inventories	Inventories	59,728		76,123	Inventories	57,116		66,076
Prepaid expenses	Prepaid expenses	61,271		40,896	Prepaid expenses	36,027		33,860
Assets held for sale	Assets held for sale	124,337		123,864	Assets held for sale	40,821		327,736
Total current assets	Total current assets	763,390		974,327	Total current assets	918,606		1,000,292
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $10,603,617 in 2020 and $9,333,646 in 2019		8,891,419		9,969,743
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,146,262 in 2021 and $11,455,305 in 2020					Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,146,262 in 2021 and $11,455,305 in 2020	8,224,538		8,269,038
Operating lease assets	Operating lease assets	779,591		598,293	Operating lease assets	973,801		927,658
Deferred income taxes	Deferred income taxes	290,006		129,287	Deferred income taxes	457,600		395,253
Deferred charges and other assets	Deferred charges and other assets	29,624		46,854	Deferred charges and other assets	29,645		28,611

Total assets	Total assets	$	10,754,030	11,718,504	Total assets	$	10,604,190	10,620,852
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY				LIABILITIES AND EQUITY
Current liabilities	Current liabilities				Current liabilities

Current maturities of long-term debt, finance lease					Current maturities of long-term debt, finance lease	$	755	0
Accounts payable	Accounts payable	$	366,205	602,096	Accounts payable	744,067		407,097
Income taxes payable	Income taxes payable	18,646		19,049	Income taxes payable	19,176		18,018
Other taxes payable	Other taxes payable	16,988		18,613	Other taxes payable	20,290		22,498
Operating lease liabilities	Operating lease liabilities	103,341		92,286	Operating lease liabilities	167,474		103,758
Other accrued liabilities	Other accrued liabilities	151,848		197,447	Other accrued liabilities	321,524		150,578
Liabilities associated with assets held for sale	Liabilities associated with assets held for sale	13,711		13,298	Liabilities associated with assets held for sale	0		14,372
Total current liabilities	Total current liabilities	670,739		942,789	Total current liabilities	1,273,286		716,321
Long-term debt, including capital lease obligation		2,956,419		2,803,381
Long-term debt, including finance lease obligation					Long-term debt, including finance lease obligation	2,762,851		2,988,067
Asset retirement obligations	Asset retirement obligations	844,545		825,794	Asset retirement obligations	817,502		816,308
Deferred credits and other liabilities	Deferred credits and other liabilities	628,904		613,407	Deferred credits and other liabilities	738,407		680,580
Non-current operating lease liabilities	Non-current operating lease liabilities	697,674		521,324	Non-current operating lease liabilities	826,713		845,088
Deferred income taxes	Deferred income taxes	182,267		207,198	Deferred income taxes	143,603		180,341

Total liabilities	Total liabilities	5,980,548		5,913,893	Total liabilities	6,562,362		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	—		—	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	931,429		949,445	Capital in excess of par value	915,181		941,692
Retained earnings	Retained earnings	5,823,426		6,614,304	Retained earnings	4,980,428		5,369,538
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(690,341)		(574,161)	Accumulated other comprehensive loss	(553,519)		(601,333)
Treasury stock	Treasury stock	(1,691,070)		(1,717,217)	Treasury stock	(1,656,591)		(1,690,661)
Murphy Shareholders' Equity	Murphy Shareholders' Equity	4,568,545		5,467,460	Murphy Shareholders' Equity	3,880,600		4,214,337
Noncontrolling interest	Noncontrolling interest	204,937		337,151	Noncontrolling interest	161,228		179,810
Total equity	Total equity	4,773,482		5,804,611	Total equity	4,041,828		4,394,147
Total liabilities and equity	Total liabilities and equity	$	10,754,030	11,718,504	Total liabilities and equity	$	10,604,190	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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars, except per share amounts)	(Thousands of dollars, except per share amounts)	2020		2019	2020	2019	(Thousands of dollars, except per share amounts)	2021		2020	2021		2020
Revenues and other income	Revenues and other income						Revenues and other income
Revenue from sales to customers	Revenue from sales to customers	$	285,745	680,436	886,303	1,309,790	Revenue from sales to customers	$	758,829	285,745	$	1,351,356	886,303
(Loss) gain on crude contracts	(Loss) gain on crude contracts	(75,880)		57,916	324,792	57,916	(Loss) gain on crude contracts	(226,245)		(75,880)	(440,630)		324,792
Gain on sale of assets and other income	Gain on sale of assets and other income	1,677		5,598	4,175	6,790	Gain on sale of assets and other income	17,059		1,677	18,902		4,175
Total revenues and other income	Total revenues and other income	211,542		743,950	1,215,270	1,374,496	Total revenues and other income	549,643		211,542	929,628		1,215,270
Costs and expenses	Costs and expenses						Costs and expenses
Lease operating expenses	Lease operating expenses	144,644		137,132	353,792	268,828	Lease operating expenses	126,413		144,644	273,577		353,792
Severance and ad valorem taxes	Severance and ad valorem taxes	6,442		13,072	15,864	23,169	Severance and ad valorem taxes	11,314		6,442	20,545		15,864
Transportation, gathering and processing	Transportation, gathering and processing	41,090		34,901	85,457	74,443	Transportation, gathering and processing	49,696		41,090	92,608		85,457
Exploration expenses, including undeveloped lease amortization	Exploration expenses, including undeveloped lease amortization	29,468		30,674	49,594	63,212	Exploration expenses, including undeveloped lease amortization	13,543		29,468	25,323		49,594
Selling and general expenses	Selling and general expenses	39,100		57,532	75,872	120,892	Selling and general expenses	29,113		39,100	58,616		75,872
Restructuring expenses	Restructuring expenses	41,397		—	41,397	—	Restructuring expenses	0		41,397	0		41,397
Depreciation, depletion and amortization	Depreciation, depletion and amortization	231,446		264,302	537,548	493,708	Depreciation, depletion and amortization	227,288		231,446	425,566		537,548
Accretion of asset retirement obligations	Accretion of asset retirement obligations	10,469		9,897	20,435	19,237	Accretion of asset retirement obligations	12,164		10,469	22,656		20,435
Impairment of assets	Impairment of assets	19,616		—	987,146	—	Impairment of assets	0		19,616	171,296		987,146
Other (benefit) expense		22,007		25,437	(23,181)	55,442
Other expense (benefit)							Other expense (benefit)	70,328		22,007	91,407		(23,181)
Total costs and expenses	Total costs and expenses	585,679		572,947	2,143,924	1,118,931	Total costs and expenses	539,859		585,679	1,181,594		2,143,924
Operating (loss) income from continuing operations		(374,137)		171,003	(928,654)	255,565
Operating income (loss) from continuing operations							Operating income (loss) from continuing operations	9,784		(374,137)	(251,966)		(928,654)
Other income (loss)	Other income (loss)						Other income (loss)
Interest and other income (loss)		(5,171)		(8,968)	(4,930)	(13,716)
Interest income and other (loss)							Interest income and other (loss)	(4,525)		(5,171)	(9,866)		(4,930)
Interest expense, net	Interest expense, net	(38,598)		(54,096)	(79,695)	(100,165)	Interest expense, net	(43,374)		(38,598)	(131,474)		(79,695)
Total other loss	Total other loss	(43,769)		(63,064)	(84,625)	(113,881)	Total other loss	(47,899)		(43,769)	(141,340)		(84,625)
(Loss) income from continuing operations before income taxes		(417,906)		107,939	(1,013,279)	141,684
Income tax (benefit) expense		(94,773)		9,115	(186,306)	19,937
(Loss) income from continuing operations		(323,133)		98,824	(826,973)	121,747
Loss from continuing operations before income taxes							Loss from continuing operations before income taxes	(38,115)		(417,906)	(393,306)		(1,013,279)
Income tax benefit							Income tax benefit	(11,177)		(94,773)	(99,336)		(186,306)
Loss from continuing operations							Loss from continuing operations	(26,938)		(323,133)	(293,970)		(826,973)
(Loss) income from discontinued operations, net of income taxes	(Loss) income from discontinued operations, net of income taxes	(1,267)		24,418	(6,129)	74,264	(Loss) income from discontinued operations, net of income taxes	(102)		(1,267)	106		(6,129)
Net (loss) income including noncontrolling interest		(324,400)		123,242	(833,102)	196,011
Less: Net (loss) income attributable to noncontrolling interest		(7,216)		30,970	(99,814)	63,557
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY		$	(317,184)	92,272	(733,288)	132,454
(LOSS) INCOME PER COMMON SHARE – BASIC
Net loss including noncontrolling interest							Net loss including noncontrolling interest	(27,040)		(324,400)	(293,864)		(833,102)
Less: Net income (loss) attributable to noncontrolling interest							Less: Net income (loss) attributable to noncontrolling interest	36,042		(7,216)	56,656		(99,814)
NET LOSS ATTRIBUTABLE TO MURPHY							NET LOSS ATTRIBUTABLE TO MURPHY	$	(63,082)	(317,184)	$	(350,520)	(733,288)
LOSS PER COMMON SHARE – BASIC							LOSS PER COMMON SHARE – BASIC
Continuing operations	Continuing operations	$	(2.05)	0.40	(4.74)	0.34	Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)
Discontinued operations	Discontinued operations	(0.01)		0.15	(0.04)	0.44	Discontinued operations	0		(0.01)	0		(0.04)
Net (loss) income		$	(2.06)	0.55	(4.78)	0.78
(LOSS) INCOME PER COMMON SHARE – DILUTED
Net loss							Net loss	$	(0.41)	(2.06)	$	(2.27)	(4.78)
LOSS PER COMMON SHARE – DILUTED							LOSS PER COMMON SHARE – DILUTED
Continuing operations	Continuing operations	$	(2.05)	0.40	(4.74)	0.34	Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)
Discontinued operations	Discontinued operations	(0.01)		0.14	(0.04)	0.43	Discontinued operations	0		(0.01)	0		(0.04)
Net (loss) income		$	(2.06)	0.54	(4.78)	0.77
Net loss							Net loss	$	(0.41)	(2.06)	$	(2.27)	(4.78)
Cash dividends per Common share	Cash dividends per Common share	0.13		0.25	0.38	0.50	Cash dividends per Common share	0.125		0.125	0.250		0.375

Average Common shares outstanding (thousands)	Average Common shares outstanding (thousands)						Average Common shares outstanding (thousands)
Basic	Basic	153,581		168,538	153,429	170,556	Basic	154,395		153,581	154,153		153,429
Diluted	Diluted	153,581		169,272	153,429	171,433	Diluted	154,395		153,581	154,153		153,429

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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
Net (loss) income including noncontrolling interest		$	(324,400)	123,242	(833,102)	196,011
Net (loss) including noncontrolling interest							Net (loss) including noncontrolling interest	$	(27,040)	(324,400)	$	(293,864)	(833,102)
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	50,568		28,606	(67,843)	54,055	Net (loss) gain from foreign currency translation	17,945		50,568	37,842		(67,843)
Retirement and postretirement benefit plans	Retirement and postretirement benefit plans	(39,234)		2,762	(48,945)	5,516	Retirement and postretirement benefit plans	4,146		(39,234)	8,282		(48,945)
Deferred loss on interest rate hedges reclassified to interest expense	Deferred loss on interest rate hedges reclassified to interest expense	309		586	608	1,171	Deferred loss on interest rate hedges reclassified to interest expense	0		309	1,690		608

Other comprehensive (loss) income	Other comprehensive (loss) income	11,643		31,954	(116,180)	60,742	Other comprehensive (loss) income	22,091		11,643	47,814		(116,180)
COMPREHENSIVE (LOSS) INCOME		$	(312,757)	155,196	(949,282)	256,753
COMPREHENSIVE (LOSS)							COMPREHENSIVE (LOSS)	$	(4,949)	(312,757)	$	(246,050)	(949,282)

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


		Six Months Ended June 30,						Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Operating Activities	Operating Activities				Operating Activities
Net (loss) income including noncontrolling interest		$	(833,102)	196,011
Adjustments to reconcile net (loss) income to net cash (required) provided by continuing operations activities:
Net (loss) including noncontrolling interest					Net (loss) including noncontrolling interest	$	(293,864)	(833,102)
Adjustments to reconcile net loss to net cash provided (required) by continuing operations activities					Adjustments to reconcile net loss to net cash provided (required) by continuing operations activities
Loss (income) from discontinued operations	Loss (income) from discontinued operations	6,129		(74,264)	Loss (income) from discontinued operations	(106)		6,129
Depreciation, depletion and amortization	Depreciation, depletion and amortization	537,548		493,708	Depreciation, depletion and amortization	425,566		537,548
Previously suspended exploration costs	Previously suspended exploration costs	7,677		12,901	Previously suspended exploration costs	633		7,677
Amortization of undeveloped leases	Amortization of undeveloped leases	14,770		15,150	Amortization of undeveloped leases	8,882		14,770
Accretion of asset retirement obligations	Accretion of asset retirement obligations	20,435		19,237	Accretion of asset retirement obligations	22,656		20,435
Impairment of assets	Impairment of assets	987,146		—	Impairment of assets	171,296		987,146
Noncash restructuring expense	Noncash restructuring expense	17,565		—	Noncash restructuring expense	0		17,565
Deferred income tax (benefit) expense		(167,902)		18,001
Deferred income tax benefit					Deferred income tax benefit	(101,195)		(167,902)

Mark to market (gain) loss on contingent consideration		(43,529)		28,890
Mark to market (gain) loss on crude contracts		(173,848)		(50,831)
Mark to market loss (gain) on contingent consideration					Mark to market loss (gain) on contingent consideration	76,677		(43,529)
Mark to market loss (gain) on crude contracts					Mark to market loss (gain) on crude contracts	284,360		(173,848)
Long-term non-cash compensation	Long-term non-cash compensation	22,760		44,755	Long-term non-cash compensation	25,318		22,760
Net decrease (increase) in noncash operating working capital		1,335		(5,366)
Net (increase) decrease in noncash working capital					Net (increase) decrease in noncash working capital	26,565		1,335
Other operating activities, net	Other operating activities, net	(27,605)		(42,761)	Other operating activities, net	39,494		(27,605)
Net cash provided by continuing operations activities	Net cash provided by continuing operations activities	369,379		655,431	Net cash provided by continuing operations activities	686,282		369,379
Investing Activities	Investing Activities				Investing Activities
Property additions and dry hole costs	Property additions and dry hole costs	(537,601)		(645,169)	Property additions and dry hole costs	(445,314)		(537,601)
Property additions for King's Quay FPS	Property additions for King's Quay FPS	(51,635)		—	Property additions for King's Quay FPS	(17,734)		(51,635)
Acquisition of oil and gas properties		—		(1,226,261)

Proceeds from sales of property, plant and equipment	Proceeds from sales of property, plant and equipment	—		16,816	Proceeds from sales of property, plant and equipment	269,363		0
Net cash required by investing activities		(589,236)		(1,854,614)
Net cash (required) by investing activities					Net cash (required) by investing activities	(193,685)		(589,236)
Financing Activities	Financing Activities				Financing Activities
Borrowings on revolving credit facility	Borrowings on revolving credit facility	370,000		1,075,000	Borrowings on revolving credit facility	165,000		370,000
Repayment of revolving credit facility	Repayment of revolving credit facility	(200,000)		—	Repayment of revolving credit facility	(365,000)		(200,000)
Retirement of debt					Retirement of debt	(576,358)		(12,225)
Debt issuance, net of cost					Debt issuance, net of cost	541,974		(613)
Early redemption of debt cost					Early redemption of debt cost	(34,177)		0
Distributions to noncontrolling interest					Distributions to noncontrolling interest	(75,238)		(32,400)
Cash dividends paid	Cash dividends paid	(57,590)		(85,503)	Cash dividends paid	(38,590)		(57,590)
Distributions to noncontrolling interest		(32,400)		(68,776)
Early retirement of debt		(12,225)		—
Withholding tax on stock-based incentive awards	Withholding tax on stock-based incentive awards	(7,247)		(6,991)	Withholding tax on stock-based incentive awards	(3,895)		(7,247)
Debt issuance, net of cost		(613)		—
Proceeds from term loan and other loans	Proceeds from term loan and other loans	371		500,000	Proceeds from term loan and other loans	0		371
Capital lease obligation payments	Capital lease obligation payments	(336)		(335)	Capital lease obligation payments	(371)		(336)
Repurchase of common stock		—		(299,924)
Net cash provided by financing activities		59,960		1,113,471

Net cash (required) provided by financing activities					Net cash (required) provided by financing activities	(386,655)		59,960
Cash Flows from Discontinued Operations ¹	Cash Flows from Discontinued Operations ¹				Cash Flows from Discontinued Operations 1
Operating activities	Operating activities	(1,202)		122,272	Operating activities	0		(1,202)
Investing activities	Investing activities	4,494		(49,798)	Investing activities	0		4,494
Financing activities	Financing activities	—		(4,914)	Financing activities	0		0
Net cash provided by discontinued operations	Net cash provided by discontinued operations	3,292		67,560	Net cash provided by discontinued operations	0		3,292
Cash transferred from discontinued operations to continuing operations		—		48,565

Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	(1,358)		3,268	Effect of exchange rate changes on cash and cash equivalents	1,552		(1,358)
Net increase (decrease) in cash and cash equivalents	Net increase (decrease) in cash and cash equivalents	(161,255)		(33,879)	Net increase (decrease) in cash and cash equivalents	107,494		(161,255)
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	$	145,505	326,044	Cash and cash equivalents at end of period	$	418,100	145,505

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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued	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
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2020 and 195,083,364 shares at June 30, 2019
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2021 and 195,100,628 shares at June 30, 2020							Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2021 and 195,100,628 shares at June 30, 2020
Balance at beginning of period	Balance at beginning of period	195,101		195,083	195,089	195,077	Balance at beginning of period	195,101		195,101	195,101		195,089
Exercise of stock options	Exercise of stock options	—		—	12	6	Exercise of stock options	—		—	—		12
Balance at end of period	Balance at end of period	195,101		195,083	195,101	195,083	Balance at end of period	195,101		195,101	195,101		195,101
Capital in Excess of Par Value	Capital in Excess of Par Value						Capital in Excess of Par Value
Balance at beginning of period	Balance at beginning of period	924,930		924,904	949,445	979,642	Balance at beginning of period	914,303		924,930	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	(587)		—	(626)		(156)
Restricted stock transactions and other	Restricted stock transactions and other	(636)		—	(33,240)	(38,732)	Restricted stock transactions and other	(5,347)		(636)	(38,347)		(33,240)
Share-based compensation	Share-based compensation	7,135		9,040	15,380	17,676	Share-based compensation	6,812		7,135	12,462		15,380
Adjustments to acquisition valuation		—		—	—	(24,519)

Balance at end of period	Balance at end of period	931,429		933,944	931,429	933,944	Balance at end of period	915,181		931,429	915,181		931,429
Retained Earnings	Retained Earnings						Retained Earnings
Balance at beginning of period	Balance at beginning of period	6,159,808		5,627,081	6,614,304	5,513,529	Balance at beginning of period	5,062,813		6,159,808	5,369,538		6,614,304
Net (loss) income for the period		(317,184)		92,272	(733,288)	132,454
Net (loss) attributable to Murphy							Net (loss) attributable to Murphy	(63,082)		(317,184)	(350,520)		(733,288)

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

Cash dividends	Cash dividends	(19,198)		(42,105)	(57,590)	(85,503)	Cash dividends	(19,303)		(19,198)	(38,590)		(57,590)
Balance at end of period	Balance at end of period	5,823,426		5,677,248	5,823,426	5,677,248	Balance at end of period	4,980,428		5,823,426	4,980,428		5,823,426
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss						Accumulated Other Comprehensive Loss
Balance at beginning of period	Balance at beginning of period	(701,984)		(580,999)	(574,161)	(609,787)	Balance at beginning of period	(575,610)		(701,984)	(601,333)		(574,161)
Foreign currency translation (loss) gain, net of income taxes		50,568		28,606	(67,843)	54,055
Foreign currency translation gain (loss), net of income taxes							Foreign currency translation gain (loss), net of income taxes	17,945		50,568	37,842		(67,843)
Retirement and postretirement benefit plans, net of income taxes	Retirement and postretirement benefit plans, net of income taxes	(39,234)		2,762	(48,945)	5,516	Retirement and postretirement benefit plans, net of income taxes	4,146		(39,234)	8,282		(48,945)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	309		586	608	1,171	Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	—		309	1,690		608

Balance at end of period	Balance at end of period	(690,341)		(549,045)	(690,341)	(549,045)	Balance at end of period	(553,519)		(690,341)	(553,519)		(690,341)
Treasury Stock	Treasury Stock						Treasury Stock
Balance at beginning of period	Balance at beginning of period	(1,691,706)		(1,217,293)	(1,717,217)	(1,249,162)	Balance at beginning of period	(1,661,416)		(1,691,706)	(1,690,661)		(1,717,217)
Purchase of treasury shares		—		(299,924)	—	(299,924)

Awarded restricted stock, net of forfeitures	Awarded restricted stock, net of forfeitures	636		—	26,147	31,869	Awarded restricted stock, net of forfeitures	4,339		636	33,545		26,147
Balance at end of period – 41,512,066 shares of Common Stock in 2020 and 32,832,771 shares of Common Stock in 2019, at cost		(1,691,070)		(1,517,217)	(1,691,070)	(1,517,217)
Exercise of stock options							Exercise of stock options	486		—	525		—
Balance at end of period – 40,665,675 shares of Common Stock in 2021 and 41,512,066 shares of Common Stock in 2020, at cost							Balance at end of period – 40,665,675 shares of Common Stock in 2021 and 41,512,066 shares of Common Stock in 2020, at cost	(1,656,591)		(1,691,070)	(1,656,591)		(1,691,070)
Murphy Shareholders’ Equity	Murphy Shareholders’ Equity	4,568,545		4,740,013	4,568,545	4,740,013	Murphy Shareholders’ Equity	3,880,600		4,568,545	3,880,600		4,568,545
Noncontrolling Interest	Noncontrolling Interest						Noncontrolling Interest
Balance at beginning of period	Balance at beginning of period	212,154		377,901	337,151	368,343	Balance at beginning of period	164,418		212,154	179,810		337,151
Acquisition closing adjustments		—		—	—	(4,592)
Net (loss) income attributable to noncontrolling interest		(7,216)		30,970	(99,814)	63,557

Net income (loss) attributable to noncontrolling interest							Net income (loss) attributable to noncontrolling interest	36,042		(7,216)	56,656		(99,814)
Distributions to noncontrolling interest owners	Distributions to noncontrolling interest owners	(1)		(50,339)	(32,400)	(68,776)	Distributions to noncontrolling interest owners	(39,232)		(1)	(75,238)		(32,400)
Balance at end of period	Balance at end of period	204,937		358,532	204,937	358,532	Balance at end of period	161,228		204,937	161,228		204,937
Total Equity	Total Equity	$	4,773,482	5,098,545	4,773,482	5,098,545	Total Equity	$	4,041,828	4,773,482	$	4,041,828	4,773,482

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Nature of Business and Interim Financial Statements

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

In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) acquisition, ~~further discussed in Note P – Acquisitions,~~ we hold a 0.5% interest in 2 variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, ~~2020,~~2021, our maximum exposure to loss was ~~$3.5~~$3.4 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, ~~2020~~2021 and ~~2019,~~2020, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

~~Financial~~Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s ~~2019~~2020 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, ~~2020~~2021 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

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

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

~~Recent Accounting Pronouncements~~

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

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

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

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

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

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

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

In the third quarter of 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations and revised all historical periods to reflect this presentation. There was no resultant change in net income attributable to Murphy.

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 six-month periods ended June 30, ~~2020,~~2021, the Company recognized ~~$285.7~~$758.8 million and ~~$886.3~~$1,351.4 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and six-month periods ended June 30, ~~2019,~~2020, the Company recognized ~~$680.4~~$285.7 million and ~~$1,309.8~~$886.3 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.


			Three Months Ended June 30,								Six Months Ended June 30,										Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)		2020				2019		2020		2019	(Thousands of dollars)			2021				2020		2021		2020
Net crude oil and condensate revenue	Net crude oil and condensate revenue													Net crude oil and condensate revenue
United States	United States	Onshore	$	54,550			193,565		185,786		328,241	United States	Onshore		$	183,267			54,550		297,757		185,786
		Offshore	150,253				352,281		497,225		691,944		Offshore		411,076				150,253		739,417		497,225
Canada	Canada	Onshore	11,527				28,031		34,910		56,972	Canada	Onshore		30,695				11,527		60,598		34,910
		Offshore	11,077				42,355		35,691		87,279		Offshore		31,772				11,077		49,834		35,691
Other	Other		(58)				3,123		1,806		5,975	Other			0				(58)		0		1,806
Total crude oil and condensate revenue	Total crude oil and condensate revenue				227,349			619,355		755,418		1,170,411		Total crude oil and condensate revenue			656,810			227,349		1,147,606		755,418

Net natural gas liquids revenue	Net natural gas liquids revenue													Net natural gas liquids revenue
United States	United States	Onshore	3,876				8,719		9,379		16,940	United States	Onshore		9,596				3,876		17,124		9,379
		Offshore	3,464				4,478		8,490		9,770		Offshore		10,766				3,464		20,820		8,490
Canada	Canada	Onshore	1,276				2,775		3,310		6,236	Canada	Onshore		3,240				1,276		7,227		3,310
Total natural gas liquids revenue	Total natural gas liquids revenue				8,616			15,972		21,179		32,946		Total natural gas liquids revenue			23,602			8,616		45,171		21,179

Net natural gas revenue	Net natural gas revenue													Net natural gas revenue
United States	United States	Onshore	4,090				7,340		9,648		14,914	United States	Onshore		6,872				4,090		13,315		9,648
		Offshore	10,665				9,219		25,660		13,696		Offshore		17,273				10,665		39,411		25,660
Canada	Canada	Onshore	35,025				28,550		74,398		77,823	Canada	Onshore		54,272				35,025		105,853		74,398
Total natural gas revenue	Total natural gas revenue				49,780			45,109		109,706		106,433		Total natural gas revenue			78,417			49,780		158,579		109,706
Total revenue from contracts with customers	Total revenue from contracts with customers				285,745			680,436		886,303		1,309,790		Total revenue from contracts with customers			758,829			285,745		1,351,356		886,303

(Loss) gain on crude contracts	(Loss) gain on crude contracts				(75,880)			57,916		324,792		57,916		(Loss) gain on crude contracts			(226,245)			(75,880)		(440,630)		324,792
Gain on sale of assets and other income	Gain on sale of assets and other income				1,677			5,598		4,175		6,790		Gain on sale of assets and other income			17,059			1,677		18,902		4,175
Total revenue and other income	Total revenue and other income				$	211,542		743,950		1,215,270		1,374,496		Total revenue and other income			$	549,643		211,542		929,628		1,215,270

Contract Balances and Asset Recognition

As of June 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were ~~$101.3~~$206.6 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 at June 30, ~~2020.~~2021.

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Performance Obligations

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

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

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

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

໿

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

~~Approximate Volumes~~2021

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Oil

Q4 2021

Fixed quantity delivery in Eagle Ford

17,000 BOED

U.S.

Natural Gas and NGL

Q1 2023

Deliveries from dedicated acreage in Eagle Ford

As produced

~~Canada~~

~~Natural Gas~~

~~Q4 2020~~

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

~~59 MMCFD~~

~~Canada~~

~~Natural Gas~~

~~Q4 2020~~

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

~~60 MMCFD~~

Canada

Natural Gas

Q4 2021

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

10 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD index pricing

8 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at CAD fixed prices

5 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD fixed pricing

20 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at USD index pricing

25 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at CAD fixed prices

38 MMCFD

Canada

Natural Gas

Q4 2024

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

3031 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

100 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

34 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD fixed pricing

15 MMCFD

Canada

Natural Gas

Q4 2026

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

3849 MMCFD

Canada

~~Natural Gas~~NGL

~~Q4 2026~~Q3 2023

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

~~11 MMCFD~~952 BOED

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

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

Note D – Property, Plant, and Equipment

Exploratory Wells

Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

AtAs of June 30, ~~2020,~~2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of ~~$180.1~~$197.5 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, ~~2020~~2021 and ~~2019.~~

(Thousands of dollars) 2020 2019
Beginning balance at January 1 $ 217,326 207,855
Additions pending the determination of proved reserves 2,328 50,307
Capitalized exploratory well costs charged to expense (39,519) (13,145)
Balance at June 30 $ 180,135 245,017

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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


(Thousands of dollars)	2021		2020
Beginning balance at January 1	$	181,616	217,326
Additions pending the determination of proved reserves	15,921		2,328

Capitalized exploratory well costs charged to expense	0		(39,519)
Balance at June 30	$	197,537	180,135

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.


		June 30,														June 30,
		2020						2019							2021		2020

(Thousands of dollars)	(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount	No. of Wells	No. of Projects	(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount	No. of Wells	No. of Projects
Aging of capitalized well costs:	Aging of capitalized well costs:								Aging of capitalized well costs:
Zero to one year	Zero to one year	$	24,429	3	3	33,125	3	2	Zero to one year	$	13,881	3	3	24,429	3	3
One to two years	One to two years	30,691		2	2	61,293	1	1	One to two years	23,811		3	3	30,691	2	2
Two to three years	Two to three years	—		—	—	27,266	1	1	Two to three years	30,562		2	2	0	0	0
Three years or more	Three years or more	125,015		6	—	123,333	5	—	Three years or more	129,283		6	0	125,015	6	0
		$	180,135	11	5	245,017	10	4		$	197,537	14	8	180,135	11	5

Of the ~~$155.7~~$183.6 million of exploratory well costs capitalized more than one year at June 30, ~~2020, $87.6~~2021, $91.5 million is in Vietnam, ~~$27.4~~$46.2 million is in the U.S., ~~$25.2~~$25.7 million is in Brunei, ~~and $15.5~~$15.4 million is in ~~Mexico.~~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.

~~Divestments~~Impairments

~~In July 2019,~~During the first quarter of 2021, the Company ~~completed a divestiture~~recorded an impairment charge 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$171.3 million ~~was recorded as part of discontinued operations on the Consolidated Statement of Operations during 2019. The Company does not anticipate tax liabilities related~~for Terra Nova due to the ~~sales proceeds. Murphy is entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020.~~

~~Acquisitions~~

~~In 2016, a Canadian subsidiary~~status, including agreements with the partners, of ~~Murphy Oil acquired a 70% operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca)~~operating and production acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of June 30, 2020, all of the carried interest had been fully utilized.

~~Impairments~~plans.

In 2020, declines in future oil and natural gas prices (principally driven by reduced demand ~~in response to~~from the COVID-19 ~~pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 39)~~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 $987.1 million to reduce the carrying values to their estimated fair values at select properties.

The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.

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


	~~Six Months Ended~~
~~(Thousands of dollars)~~	~~June 30, 2020~~
~~U.S.~~	$	~~947,437~~

~~Other Foreign~~	~~39,709~~
	$	~~987,146~~


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

	$	171,296	987,146

Divestments

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – ~~Discontinued Operations and~~ Assets Held for Sale and Discontinued Operations

The Company has accounted for its former ~~Malaysian exploration~~U.K. 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 six-month periods ended June 30, ~~2020~~2021 and ~~2019~~2020 were as follows:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021		2020
Revenues	Revenues	$	1	159,961	4,074	355,373	Revenues	$	246	1	$	658	4,074
Costs and expenses	Costs and expenses						Costs and expenses
Lease operating expenses		—		58,160	—	120,876
Depreciation, depletion and amortization		—		2,345	—	33,698

Other costs and expenses (benefits)	Other costs and expenses (benefits)	1,268		57,401	10,203	70,481	Other costs and expenses (benefits)	348		1,268	552		10,203
(Loss) income before taxes	(Loss) income before taxes	(1,267)		42,055	(6,129)	130,318	(Loss) income before taxes	(102)		(1,267)	106		(6,129)
Income tax expense	Income tax expense	—		17,637	—	56,054	Income tax expense	0		0	0		0
(Loss) income from discontinued operations	(Loss) income from discontinued operations	$	(1,267)	24,418	(6,129)	74,264	(Loss) income from discontinued operations	$	(102)	(1,267)	$	106	(6,129)

~~The following table presents~~As of June 30, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the ~~major categories~~net property, plant equipment of ~~assets and liabilities of the~~CA-2 project in Brunei ~~exploration and production operations, the U.K. refining and marketing operations~~ and the Company’s office building in El Dorado, ~~AR and 2 airplanes that are reflected as~~Arkansas. As of June 30, 2021, the CA-1 asset in Brunei is no longer being marketed for sale.

As of December 31, 2020, assets held for sale onincluded the King’s Quay Floating Production System (FPS) of $250.1 million (sold in March 2021), the Brunei exploration and production properties, and the Company’s ~~Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019.~~office building in El Dorado, Arkansas.


(Thousands of dollars)	(Thousands of dollars)	June 30, 2020		December 31, 2019	(Thousands of dollars)	June 30, 2021		December 31, 2020
Current assets	Current assets				Current assets
Cash	Cash	$	30,898	25,185	Cash	$	0	10,185
Accounts receivable		425		4,834

Inventories	Inventories	406		406	Inventories	0		406
Prepaid expenses and other		814		1,882

Property, plant, and equipment, net	Property, plant, and equipment, net	82,353		82,116	Property, plant, and equipment, net	40,820		307,704
Deferred income taxes and other assets	Deferred income taxes and other assets	9,441		9,441	Deferred income taxes and other assets	—		9,441

Total current assets associated with assets held for sale	Total current assets associated with assets held for sale	124,337		123,864	Total current assets associated with assets held for sale	$	40,820	327,736

Current liabilities	Current liabilities				Current liabilities
Accounts payable	Accounts payable	$	4,342	3,702	Accounts payable	$	0	5,306

Other accrued liabilities					Other accrued liabilities	0		45
Current maturities of long-term debt (finance lease)	Current maturities of long-term debt (finance lease)	720		705	Current maturities of long-term debt (finance lease)	0		737
Taxes payable	Taxes payable	1,510		1,411	Taxes payable	0		1,510

Long-term debt (finance lease)	Long-term debt (finance lease)	6,889		7,240	Long-term debt (finance lease)	0		6,513
Asset retirement obligation	Asset retirement obligation	250		240	Asset retirement obligation	0		261
Total current liabilities associated with assets held for sale	Total current liabilities associated with assets held for sale	13,711		13,298	Total current liabilities associated with assets held for sale	$	0	14,372

Note F – Financing Arrangements and Debt

As of June 30, ~~2020,~~2021, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At June 30, ~~2020,~~2021, the Company had ~~$170.0 million~~0 outstanding borrowings under the RCF and ~~$3.7~~$31.0 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, ~~2020,~~2021, the interest rate in effect on borrowings under the facility was ~~1.86%~~1.78%. At June 30, ~~2020,~~2021, the Company was in compliance with all covenants related to the RCF.

In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.0 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financing Arrangements and Debt (Contd.)

(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 six months ended June 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the six months ended June 30, 2021.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2021.

~~Table~~Subsequent to quarter end, the Company issued a notice of ~~Contents~~

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

~~Note F – Financing Arrangements~~partial redemption with respect to $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and ~~Debt~~ ~~(Contd.)~~

unpaid interest, if any, to, but not including, the date of redemption. The redemption date of the 2024 Notes will be August 16, 2021.

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.໿


		Six Months Ended June 30,						Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:	Net (increase) decrease in operating working capital, excluding cash and cash equivalents:				Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹	(Increase) decrease in accounts receivable ¹	$	227,710	(141,793)	(Increase) decrease in accounts receivable ¹	$	(104,775)	227,710
(Increase) decrease in inventories		13,968		(617)
(Increase) decrease in prepaid expenses		(20,712)		(12,190)
Decrease in inventories					Decrease in inventories	8,938		13,968
(Increase) in prepaid expenses					(Increase) in prepaid expenses	(1,945)		(20,712)
Increase (decrease) in accounts payable and accrued liabilities ¹	Increase (decrease) in accounts payable and accrued liabilities ¹	(219,228)		147,569	Increase (decrease) in accounts payable and accrued liabilities ¹	124,699		(219,228)
Increase (decrease) in income taxes payable		(403)		1,665
Net (increase) decrease in noncash operating working capital		$	1,335	(5,366)
(Decrease) in income taxes payable					(Decrease) in income taxes payable	(352)		(403)
Net decrease in noncash operating working capital					Net decrease in noncash operating working capital	$	26,565	1,335
Supplementary disclosures:	Supplementary disclosures:				Supplementary disclosures:
Cash income taxes paid, net of refunds	Cash income taxes paid, net of refunds	$	(7)	79	Cash income taxes paid, net of refunds	$	1,474	(7)
Interest paid, net of amounts capitalized of $4.9 million in 2020 and $0 million in 2019		100,745		102,802
Interest paid, net of amounts capitalized of $7.4 million in 2021 and $4.9 million in 2020					Interest paid, net of amounts capitalized of $7.4 million in 2021 and $4.9 million in 2020	80,546		100,745

Non-cash investing activities:	Non-cash investing activities:				Non-cash investing activities:
Asset retirement costs capitalized ²	Asset retirement costs capitalized ²	$	6,342	38,396	Asset retirement costs capitalized ²	$	6,669	6,342
(Increase) decrease in capital expenditure accrual		58,602		(65,830)
Decrease in capital expenditure accrual					Decrease in capital expenditure accrual	20,614		58,602

¹Excludes 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~~Excludes non-cash capitalized cost offset by impairment of ~~the LLOG acquisition of~~ $74.4 million related to Terra Nova in 2021.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Employee and Retiree Benefit Plans

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

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

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


		Three Months Ended June 30,										Three Months Ended June 30,
		Pension Benefits				Other Postretirement Benefits					Pension Benefits		Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021	2020
Service cost	Service cost	$	2,166	2,062	446	420	Service cost	$	1,768	2,166	327	446
Interest cost	Interest cost	5,763		7,100	794	943	Interest cost	4,300		5,763	521	794
Expected return on plan assets	Expected return on plan assets	(6,297)		(6,370)	—	—	Expected return on plan assets	(6,155)		(6,297)	0	0
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	183		246	—	(97)	Amortization of prior service cost (credit)	156		183	0	0
Recognized actuarial loss	Recognized actuarial loss	4,264		3,508	—	—	Recognized actuarial loss	5,281		4,264	(8)	0
Net periodic benefit expense	Net periodic benefit expense	6,079		6,546	1,240	1,266	Net periodic benefit expense	5,350		6,079	840	1,240
Other - curtailment	Other - curtailment	586		—	(1,825)	—	Other - curtailment	0		586	0	(1,825)
Other - special termination benefits	Other - special termination benefits	8,435		—	—	—	Other - special termination benefits	0		8,435	0	0
Total net periodic benefit expense	Total net periodic benefit expense	$	15,100	6,546	(585)	1,266	Total net periodic benefit expense	$	5,350	15,100	840	(585)

		Six Months Ended June 30,										Six Months Ended June 30,
		Pension Benefits				Other Postretirement Benefits					Pension Benefits		Other Postretirement Benefits
(Thousands of dollars)	(Thousands of dollars)	2020		2019	2020	2019	(Thousands of dollars)	2021		2020	2021	2020
Service cost	Service cost	$	4,332	4,124	893	840	Service cost	$	3,536	4,332	653	893
Interest cost	Interest cost	11,554		14,251	1,588	1,888	Interest cost	8,586		11,554	1,042	1,588
Expected return on plan assets	Expected return on plan assets	(12,641)		(12,830)	—	—	Expected return on plan assets	(12,288)		(12,641)	0	0
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	366		493	—	(195)	Amortization of prior service cost (credit)	312		366	0	0
Recognized actuarial loss	Recognized actuarial loss	8,533		7,022	—	—	Recognized actuarial loss	10,560		8,533	(15)	0
Net periodic benefit expense	Net periodic benefit expense	12,144		13,060	2,481	2,533	Net periodic benefit expense	$	10,706	12,144	1,680	2,481
Other - curtailment	Other - curtailment	586		—	(1,825)	—	Other - curtailment	0		586	0	(1,825)
Other - special termination benefits	Other - special termination benefits	8,435		—	—	��	Other - special termination benefits	0		8,435	0	0
Total net periodic benefit expense	Total net periodic benefit expense	$	21,165	13,060	656	2,533	Total net periodic benefit expense	$	10,706	21,165	1,680	656

The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are included 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.~~

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

During the six-month period ended June 30, ~~2020,~~2021, the Company made contributions of ~~$15.3~~$19.5 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 $22.4 million.

Note I – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The 2017 Annual Incentive Plan (2017 Annual Plan) 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

other employees. Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

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

During the first six months of 2021, the Committee granted the following awards from the 2020 Long-Term Plan:

2020 Long-Term Incentive Plan

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Performance Based RSUs 1

1,156,800

February 2, 2021

16.03

Monte Carlo at Grant Date

Time Based RSUs 2

385,600

February 2, 2021

12.30

Average Stock Price at Grant Date

Cash Settled RSUs 3

1,022,700

February 2, 2021

12.30

Average Stock Price at Grant Date

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

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

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

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

In the first quarter of 2020, the Committee granted 999,700 performance-based RSUs and 340,600 time-based RSUs to certain employees under the 2018 Long-Term Plan. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $21.51 per unit. The fair value of the time-based RSUs was estimated based on the fair market value ofAt the Company’s ~~stock~~annual stockholders’ meeting held on May 12, 2021, shareholders approved the ~~date~~replacement of grant of $21.68 per unit. Additionally, in February 2020, the Committee granted 1,152,500 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2020 was $21.68. Also, in February, the Committee granted 106,248 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. ~~These units~~The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan. All awards on or after May 12, 2021, will be made under the 2021 NED Plan.

During the first six months of 2021, the Committee granted the following awards to Non-Employee Directors:

2018 Stock Plan for Non-Employee Directors

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Time Based RSUs 1

182,652

February 3, 2021

13.14

Closing Stock Price at Grant Date

1 Non-employee directors time-based RSUs are scheduled to vest ~~on the third anniversary of the date of grant. The estimated fair value of these awards was $22.59 per unit on date of grant.~~in February 2022.

2021 Stock Plan for Non-Employee Directors

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Time Based RSUs 1

5,655

June 10, 2021

23.58

Closing Stock Price at Grant Date

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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


		Six Months Ended June 30,						Six Months Ended June 30,
(Thousands of dollars)	(Thousands of dollars)	2020		2019	(Thousands of dollars)	2021		2020
Compensation charged against income before tax benefit	Compensation charged against income before tax benefit	$	10,272	30,003	Compensation charged against income before tax benefit	$	18,045	10,272
Related income tax (expense) benefit recognized in income	Related income tax (expense) benefit recognized in income	769		4,387	Related income tax (expense) benefit recognized in income	2,478		769

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

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

Note J – Earnings ~~per~~Per Share

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


		Three Months Ended June 30,			Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	(Weighted-average shares)	2020	2019	2020	2019	(Weighted-average shares)	2021	2020	2021	2020
Basic method	Basic method	153,580,758	168,537,896	153,428,666	170,555,685	Basic method	154,394,602	153,580,758	154,153,158	153,428,666
Dilutive stock options and restricted stock units ¹	Dilutive stock options and restricted stock units ¹	—	734,567	—	877,007	Dilutive stock options and restricted stock units ¹	0	0	0	0
Diluted method	Diluted method	153,580,758	169,272,463	153,428,666	171,432,692	Diluted method	154,394,602	153,580,758	154,153,158	153,428,666

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

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


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Antidilutive stock options excluded from diluted shares	Antidilutive stock options excluded from diluted shares	2,187,235		2,927,469		2,396,920		3,066,166		Antidilutive stock options excluded from diluted shares	1,379,481		2,187,235		1,592,812		2,396,920
Weighted average price of these options	Weighted average price of these options	$	39.24	$	45.38	$	40.83	$	45.66	Weighted average price of these options	$	33.79	$	39.24	$	35.07	$	40.83

Note K – Income Taxes

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


		2020	2019		2021	2020
Three months ended June 30,	Three months ended June 30,	22.7%	8.4%	Three months ended June 30,	29.3%	22.7%
Six months ended June 30,	Six months ended June 30,	18.4%	14.1%	Six months ended June 30,	25.3%	18.4%

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

The effective tax rate for the three-month period ended June 30, 2020 iswas higher than the ~~U.S.~~ statutory tax rate of 21% principally due to a research and development tax credit in Canada, which has the impact of increasing the effective tax rate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K– Income Taxes (Contd.)

The effective tax rate for the ~~three-month~~six-month period ended June 30, ~~2019~~2021 was ~~below~~above the U.S. statutory tax rate of 21% primarily due to ~~an enacted future change~~loss generated in ~~the Alberta provincial corporate income~~Canada, which has a higher tax rate, ~~in Canada that reduced the future deferred tax liability by $13 million and~~as well as no tax applied to the pre-tax income of the noncontrolling interest in MP ~~Gulf of Mexico, LLC (MP GOM).~~GOM.

The effective tax rate for the six-month period ended June 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 six-month period ended June 30, 2019 was below the statutory tax rate of 21% due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability $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 June 30, ~~2020,~~2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – ~~2015;~~2016; Malaysia – ~~2013;~~2014; and United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of

~~Table of Contents~~

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

~~Note K– Income Taxes~~ ~~(Contd.)~~

2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Note L – Financial Instruments and Risk Management

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

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

Commodity Price Risks

At June 30, ~~2020,~~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 ~~2,000~~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 ~~$41.54.~~$44.88. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.

At June 30, ~~2019,~~2020, the Company had ~~20,000~~45,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of December ~~2019~~2020 at an average price of ~~$63.64~~$56.42, and ~~20,000~~2,000 barrels per day in WTI crude oil swap ~~financial~~ contracts maturing from January through December ~~2020~~2021 at an average price of ~~$60.10.~~$41.54.

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

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

June 30, 2020 December 31, 2019
(Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives
Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value
Commodity Accounts receivable $ 157,809 Accounts payable $ (33,364)

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

Gain (Loss) Gain (Loss)
(Thousands of dollars) Statement of Operations Location Three Months Ended June 30, Six months ended June 30,
Type of Derivative Contract 2020 2019 2020 2019
Commodity (Loss) gain on crude contracts $ (75,880) 57,916 $ 324,792 57,916

~~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 six-month periods ended June 30, 2020 and 2019, $0.8 million and $1.5 million, respectively, of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at June 30, 2020 was $2.3 million and is recorded, net of income taxes of $0.6 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.8 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2020.

June 30, 2021

December 31, 2020

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

13,050

Accounts payable

(354,366)

Accounts payable

(89,842)

Deferred credits and other liabilities

(71,259)

Deferred credits and other liabilities

(12,833)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

For the three-month and six-month periods ended June 30, 2021 and 2020, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.


		Gain (Loss)			Gain (Loss)
(Thousands of dollars)	Statement of Operations Location	Three Months Ended June 30,			Six months ended June 30,
Type of Derivative Contract		2021		2020	2021		2020
Commodity	(Loss) gain on crude contracts	$	(226,245)	(75,880)	$	(440,630)	324,792

Fair Values – Recurring

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

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


		June 30, 2020								December 31, 2019									June 30, 2021		December 31, 2020
(Thousands of dollars)	(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total	(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:	Assets:										Assets:
Commodity derivative contracts	Commodity derivative contracts	$	—	157,809	—	157,809	—	—	—	—	Commodity derivative contracts	$	0	0	0	0	0	13,050	0	13,050
		$	—	157,809	—	157,809	—	—	—	—		$	0	0	0	0	0	13,050	0	13,050

Liabilities:	Liabilities:										Liabilities:
Nonqualified employee savings plan											Nonqualified employee savings plan	$	17,188	0	0	17,188	14,988	0	0	14,988
Commodity derivative contracts	Commodity derivative contracts	$	—	—	—	—	—	33,364	—	33,364	Commodity derivative contracts	0		425,625	0	425,625	0	102,675	0	102,675
Nonqualified employee savings plans		15,703		—	—	15,703	17,035	—	—	17,035
Contingent consideration	Contingent consideration	—		—	103,258	103,258	—	—	146,787	146,787	Contingent consideration	0		0	209,682	209,682	0	0	133,004	133,004
		$	15,703	—	103,258	118,961	17,035	33,364	146,787	197,186		$	17,188	425,625	209,682	652,495	14,988	102,675	133,004	250,667

The fair value of ~~WTI~~commodity (WTI crude ~~oil~~oil) derivative contracts in ~~2020~~2021 and ~~2019~~2020 were based on active market quotes for WTI crude oil. The before tax income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts 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 ~~(income)~~ expense (benefit) in the Consolidated Statements of Operations. ~~Any remaining contingent~~Contingent consideration is payable ~~will be due~~ annually in years ~~2021~~2022 to 2026.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were 0 offsetting positions recorded at June 30, ~~2020~~2021 and December 31, ~~2019.~~2020.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Accumulated Other Comprehensive Loss

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

~~Table of Contents~~

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


(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Deferred Loss on Interest Rate Derivative Hedges		Total
Balance at December 31, 2020	$	(324,011)	(275,632)		(1,690)		(601,333)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	37,842		0		0		37,842
Reclassifications to income	0		8,282	¹	1,690	²	9,972
Net other comprehensive income (loss)	37,842		8,282		1,690		47,814
Balance at June 30, 2021	$	(286,169)	(267,350)		0		(553,519)

(Thousands of dollars) Foreign
Currency
Translation
Gains (Losses) Retirement
and
Postretirement
Benefit Plan
Adjustments Deferred
Loss on
Interest Rate
Derivative
Hedges Total
Balance at December 31, 2019 $ (353,252) (218,015) (2,894) (574,161)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings (67,843) (55,707) — (123,550)
Reclassifications to income — �� 6,762 ¹ 608 ² 7,370
Net other comprehensive income (loss) (67,843) (48,945) 608 (116,180)
Balance at June 30, 2020 (421,095) (266,960) (2,286) (690,341)

¹Reclassifications before taxes of ~~$8,987~~ $10,513 are included in the computation of net periodic benefit expense for the six-month period ended June 30, ~~2020.~~2021. See Note H for additional information. Related income taxes of ~~$2,225~~ $2,231 are included in Income tax expense (benefit) for the six-month period ended June 30, ~~2020.~~2021.

²Reclassifications before taxes of ~~$769~~ $2,140 are included in Interest expense, net, for the six-month period ended June 30, ~~2020.~~2021. Related income taxes of ~~$161~~ $450 are included in Income tax expense (benefit) for the six-month period ended June 30, ~~2020.~~2021. See Note L for additional information.

Note N – Environmental and Other Contingencies

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

ENVIRONMENTAL 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 obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income/ (loss), financial condition or liquidity in a future period.also

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and ~~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 June 30, 2020		Three Months Ended June 30, 2020			Three Months Ended June 30, 2019						Total Assets at June 30, 2021		Three Months Ended June 30, 2021				Three Months Ended June 30, 2020
(Millions of dollars)	(Millions of dollars)				External Revenues	Income (Loss)	External Revenues		Income (Loss)		(Millions of dollars)	Total Assets at June 30, 2021			Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹	Exploration and production ¹							Exploration and production ¹
United States	United States	$	7,363.8	228.3	(143.1)	576.7	133.0	United States		$	6,868.2	648.9	194.7		228.3		(143.1)
Canada	Canada	2,184.9		59.2	(19.5)	102.0	(5.9)	Canada		2,366.7		120.6	12.7		59.2		(19.5)
Other	Other	269.2		—	(9.0)	3.1	(3.4)	Other		270.4		0	(10.4)		0		(9.0)
Total exploration and production	Total exploration and production	9,817.9		287.5	(171.6)	681.8	123.7	Total exploration and production		9,505.3		769.5	197.0		287.5		(171.6)
Corporate	Corporate	915.7		(76.0)	(151.6)	62.2	(24.9)	Corporate		1,097.7		(219.9)	(223.9)		(76.0)		(151.6)
Assets/revenue/income (loss) from continuing operations		10,733.6		211.5	(323.2)	744.0	98.8
Continuing operations								Continuing operations		10,603.0		549.6	(26.9)		211.5		(323.2)
Discontinued operations, net of tax	Discontinued operations, net of tax	20.4		—	(1.2)	—	24.4	Discontinued operations, net of tax		1.2		0	(0.1)		0		(1.2)
Total	Total	$	10,754.0	211.5	(324.4)	744.0	123.2	Total		$	10,604.2	549.6	(27.0)		211.5		(324.4)

				Six Months Ended June 30, 2020			Six Months Ended June 30, 2019								Six Months Ended June 30, 2021				Six Months Ended June 30, 2020
				External Revenues	Income (Loss)	External Revenues	Income (Loss)
(Millions of dollars)								(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			739.8	(839.1)	1,077.5	249.2	United States				1,139.2	313.7		739.8		(839.1)
Canada	Canada			148.9	(26.4)	228.9	1.6	Canada				224.6	(111.6)		148.9		(26.4)
Other	Other			1.8	(61.3)	6.0	(31.7)	Other				0	(17.3)		1.8		(61.3)
Total exploration and production	Total exploration and production			890.5	(926.8)	1,312.4	219.1	Total exploration and production				1,363.8	184.8		890.5		(926.8)
Corporate	Corporate			324.8	99.8	62.1	(97.4)	Corporate				(434.2)	(478.8)		324.8		99.8
Assets/revenue/income (loss) from continuing operations				1,215.3	(827.0)	1,374.5	121.7
Continuing operations								Continuing operations				929.6	(294.0)		1,215.3		(827.0)
Discontinued operations, net of tax	Discontinued operations, net of tax			—	(6.1)	—	74.3	Discontinued operations, net of tax				0	0.1		0		(6.1)
Total	Total			1,215.3	(833.1)	1,374.5	196.0	Total				929.6	(293.9)		1,215.3		(833.1)

¹ Additional details about results of oil and natural gas operations are presented in the table on pages 2726 and ~~28.~~27.

2120

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – ~~Acquisitions~~Leases

~~LLOG Acquisition~~:Nature of Leases

~~In June 2019,~~The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 19 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company ~~announced~~and lessor. Purchase options also exist for certain leases.

Related Expenses

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


		Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of dollars)	Financial Statement Category	2021		2020		2021		2020
Operating lease 1,2	Lease operating expenses	$	48,049	$	53,588	$	94,133	125,189
Operating lease 2	Transportation, gathering and processing	9,982		9,137		19,758		19,063
Operating lease 2	Selling and general expense	2,453		3,281		5,273		6,750
Operating lease 2	Other operating expense	2,427		4,201		4,842		4,615
Operating lease 2	Property, plant and equipment	26,738		13,104		31,634		37,660

Operating lease	Impairment of assets	0		6,555		0		6,555
Finance lease

Interest on lease liabilities	Interest expense, net	86		92		172		188
Sublease income	Other income	(662)		(336)		(958)		(642)
Net lease expense		$	89,073	$	89,636	$	154,854	199,392

1 Variable lease expenses. The three and six months ended June 30, 2021 included variable lease expenses of 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~~$8.2 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~~$13.5 million; and ~~2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.~~

~~The following table contains the preliminary purchase price allocations at fair value:~~


~~(Thousands of dollars)~~	LLOG (Final)
~~Cash consideration paid~~	$	~~1,236,165~~
~~Contingent consideration~~	~~89,444~~
~~Total purchase consideration~~	~~1,325,609~~
~~(Thousands of dollars)~~
~~Fair value of Property, plant and equipment~~	~~1,356,185~~
~~Other assets~~	~~6,697~~
~~Less: Asset retirement obligations~~	~~(37,273)~~
~~Total net assets~~	$	~~1,325,609~~

The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.

~~Results of Operations~~

~~Murphy’s Consolidated Statement of Operations~~ for the three ~~month period ended June 30, 2020, included additional revenues of $40.9 million~~ and ~~pre-tax loss of $31.6 million attributable to the acquired LLOG assets. For the~~ six months ended June 30, 2020 ~~additional revenues~~included variable lease expenses of ~~$134.5~~$6.0 million and ~~pre-tax loss~~$12.3 million, respectively, primarily related to additional volumes processed at a gas processing plant.

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

Maturity of ~~$437.9 million attributable to~~Lease Liabilities


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

1Includes both the ~~acquired LLOG assets (including impairment expense of $432.9 million).~~

~~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,~~current 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 in the second quarter 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-offlong-term portion 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. All Restructuring charges have been recorded in the Corporate segment.~~

liabilities.

2221

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note QP – ~~Restructuring Charges~~Leases (Contd.)

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


~~(Thousands of dollars)~~	~~Three Months Ended~~ June 30, ~~2020~~2021
~~Severance~~Weighted average remaining lease term:	$	~~19,867~~
~~Pension and termination benefit charges~~	~~10,913~~
~~Contract exit costs and other~~	~~10,617~~
~~Restructuring charges~~	$	~~41,397~~

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


~~(Thousands of dollars)~~Operating leases	11 years
~~Restructuring accruals~~Finance leases	$		~~23,832~~	8 years
~~Utilizations~~Weighted average discount rate:
Operating leases	~~(7,169)~~5.4	%
~~Liability at June 30, 2020~~Finance leases	$4.7	~~16,663~~	%

Other Information


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

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

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

In 2021, the ~~first half~~global dissemination of ~~2020~~several vaccinations in response to the ~~continued spread of~~ongoing coronavirus disease 2019 (COVID-19) pandemic has led to ~~disruption~~increased economic activity and subsequently increased demand for oil and gas. However emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the ~~global economy and a weakness in~~outlook for future demand for ~~crude oil. Additionally, certain major global suppliers of crude~~ oil ~~announced supply increases~~and gas, and hence volatility in current and future prices for Murphy’s product.

In the ~~first quarter of 2020 which resulted in a contribution to the lower global commodity prices in the first~~current quarter and ~~early second quarter. Subsequent~~first half of 2021, overall energy demand has recovered significantly compared to ~~the supply increases the~~2020. The OPEC+ group of oil producing countries ~~agreed~~(OPEC+) continues to constrain supply, ~~restrictions which helped support~~however these are being gradually scaled back as 2021 progresses. OPEC+ last year cut production by 10 million barrels per day (bpd) following the COVID-19 demand reduction. It has gradually reinstated supply so that the curtailments are approximately 5.8 million bpd at the end of June 2021. From July to December 2021 OPEC+ has reported it will increase supply by a 0.4 million bpd a month, with aims to fully phase out cuts by September 2022.

Overall the combination of OPEC+ supply constraints and the increase in demand driven by the global COVID-19 vaccine roll out has provided upwards pressure to the oil price inwhich directly impacts the ~~latter part of the second quarter. The reduction in commodity prices~~Company’s product revenue from sales compared to ~~2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 36. Low oil demand continues.~~one year ago.

For the three months ended June 30, ~~2020,~~2021, West Texas Intermediate (WTI) crude oil prices averaged approximately ~~$28~~$66 per barrel (compared to ~~$46~~$58 in the first quarter of ~~2020~~2021 and ~~$60~~$28 in the second quarter of ~~2019)~~2020). The closing price for WTI at the end of the second quarter of ~~2020~~2021 was approximately ~~$38~~$71 per barrel, reflecting a ~~36% reduction~~52% increase from the price at the end of ~~2019.~~2020 and a 14% increase from the first quarter 2021 closing price. The average price in July ~~2020~~2021 was ~~$40.77~~$72.43 per barrel. As of close on August ~~4, 2020 closing,~~3, 2021, the NYMEX WTI forward curve price for ~~September through December 2020 was $42.07~~the remainder of 2021 and 2022 were $69.71 and $65.34 per ~~barrel.~~barrel, respectively.

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

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

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

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

During the six months ended June 30, ~~2020.~~

For the three months ended June 30, 2019, the Company produced 171 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $1.6 billion in capital expenditures (on a value of work done basis) in the second quarter of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $98.8 million (which includes income attributable to noncontrolling interest of $31.0 million) for the three months ended June 30, 2019.

For the six months ended June 30, 2019, the Company produced 166 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations which excludes Malaysia as it is held for sale. The Company invested $2.0 billion in capital expenditures (on a value of work done basis) in the first half of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $121.7 million (which includes income attributable to noncontrolling interest of $63.6 million) for the six months ended June 30, 2019.

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

Table of Contents

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

Summary (contd.)

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

In the first half of 2021, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a ~~result~~transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of ~~the LLOG acquisition~~Murphy’s entire 50% interest in the ~~second quarter~~King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of ~~2019.~~project costs from inception to closing with proceeds of $267.7 million.

Also, in the first half of 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing in July 2028. The ~~additional income~~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 ~~higher volumes was offset by lower average oil prices that were below average comparable benchmark prices during 2019. The results~~issue are ~~explained in more detail below.~~reported net of costs to issue on the balance sheet.

Results of Operations

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

Income (Loss)
Three Months Ended June 30, Six Months Ended June 30,
(Millions of dollars) 2020 2019 2020 2019
Exploration and production $ (171.6) 123.7 (926.8) 219.1
Corporate and other (151.6) (24.9) 99.8 (97.4)
(Loss) income from continuing operations (323.2) 98.8 (827.0) 121.7
Discontinued operations ¹ (1.2) 24.4 (6.1) 74.3
Net (loss) income including noncontrolling interest $ (324.4) 123.2 (833.1) 196.0

~~Table of Contents~~

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


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

¹The 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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,		Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2020		2019	2020	2019	(Millions of dollars)	2021		2020	2021	2020
Exploration and production	Exploration and production						Exploration and production
United States	United States	$	(143.1)	133.0	(839.1)	249.2	United States	$	194.7	(143.1)	313.7	(839.1)
Canada	Canada	(19.5)		(5.9)	(26.4)	1.6	Canada	12.7		(19.5)	(111.6)	(26.4)
Other	Other	(9.0)		(3.4)	(61.3)	(31.7)	Other	(10.4)		(9.0)	(17.3)	(61.3)
Total	Total	$	(171.6)	123.7	(926.8)	219.1	Total	$	197.0	(171.6)	184.8	(926.8)

2524

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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,		Six Months Ended June 30,
(Millions of dollars, except per barrel of oil equivalents sold)	(Millions of dollars, except per barrel of oil equivalents sold)	2020		2019	2020	2019	(Millions of dollars, except per barrel of oil equivalents sold)	2021		2020	2021	2020
Net (loss) income attributable to Murphy (GAAP)		$	(317.1)	92.3	(733.2)	132.5
Income tax (benefit) expense		(94.8)		9.1	(186.3)	19.9
Net loss attributable to Murphy (GAAP)							Net loss attributable to Murphy (GAAP)	$	(63.1)	(317.1)	(350.5)	(733.2)
Income tax benefit							Income tax benefit	(11.2)		(94.8)	(99.3)	(186.3)
Interest expense, net	Interest expense, net	38.6		54.1	79.7	100.2	Interest expense, net	43.4		38.6	131.5	79.7
Depreciation, depletion and amortization expense ¹	Depreciation, depletion and amortization expense ¹	219.1		246.0	505.3	458.1	Depreciation, depletion and amortization expense ¹	217.3		219.1	405.6	505.3
EBITDA attributable to Murphy (Non-GAAP)	EBITDA attributable to Murphy (Non-GAAP)	(154.2)		401.5	(334.5)	710.7	EBITDA attributable to Murphy (Non-GAAP)	186.4		(154.2)	87.3	(334.5)
Mark-to-market loss (gain) on crude oil derivative contracts							Mark-to-market loss (gain) on crude oil derivative contracts	130.9		184.5	284.4	(173.8)
Impairment of assets ¹	Impairment of assets ¹	19.6		—	886.0	—	Impairment of assets ¹	—		19.6	171.3	886.0
Mark-to-market (gain) loss on crude oil derivative contracts		184.5		(50.8)	(173.8)	(50.8)
Mark-to-market (gain) loss on contingent consideration		15.7		15.4	(43.5)	28.9
Mark-to-market loss (gain) on contingent consideration							Mark-to-market loss (gain) on contingent consideration	61.8		15.7	76.7	(43.5)
Accretion of asset retirement obligations ¹							Accretion of asset retirement obligations ¹	9.5		10.5	20.0	20.4
Unutilized rig charges							Unutilized rig charges	2.5		4.5	5.3	8.0
Foreign exchange losses (gains)							Foreign exchange losses (gains)	—		1.4	1.3	(3.3)
Discontinued operations (income) loss							Discontinued operations (income) loss	0.1		1.2	(0.1)	6.1
Restructuring expenses	Restructuring expenses	41.4		—	41.4	—	Restructuring expenses	—		41.4	—	41.4
Accretion of asset retirement obligations		10.5		9.9	20.4	19.2
Discontinued operations loss (income)		1.2		(24.4)	6.1	(74.3)
Inventory loss	Inventory loss	—		—	4.8	—	Inventory loss	—		—	—	4.8
Foreign exchange (gains) losses		1.4		3.0	(3.3)	5.6
Unutilized rig charges		4.5		—	8.0	—
Business development transaction costs		—		7.8	—	20.3
Write-off of previously suspended exploration wells		—		—	—	13.2

Adjusted EBITDA attributable to Murphy (Non-GAAP)	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	124.6	362.4	411.6	672.8	Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	391.2	124.6	646.2	411.6

Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	15,242		14,269	32,312	27,766	Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)	15,648		15,242	29,318	32,312

Adjusted EBITDA per barrel of oil equivalents sold	Adjusted EBITDA per barrel of oil equivalents sold	8.17		25.40	12.74	24.23	Adjusted EBITDA per barrel of oil equivalents sold	$	25.00	8.17	22.04	12.74

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

Table of Contents

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

Results of Operations (contd.)

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


(Millions of dollars)	United States 1		Canada	Other	Total
Three Months Ended June 30, 2021
Oil and gas sales and other operating revenues	$	648.9	120.6	—	769.5
Lease operating expenses	90.5		35.8	—	126.3
Severance and ad valorem taxes	10.9		0.5	—	11.4
Transportation, gathering and processing	33.6		16.1	—	49.7
Depreciation, depletion and amortization	180.0		43.5	0.5	224.0

Accretion of asset retirement obligations	9.2		3.0	—	12.2
Exploration expenses
Dry holes and previously suspended exploration costs	(0.1)		—	—	(0.1)
Geological and geophysical	2.1		—	0.8	2.9
Other exploration	2.3		0.1	4.1	6.5
	4.3		0.1	4.9	9.3
Undeveloped lease amortization	2.5		—	1.8	4.3
Total exploration expenses	6.8		0.1	6.7	13.6
Selling and general expenses	5.3		3.9	2.1	11.3
Other	72.9		0.9	0.3	74.1
Results of operations before taxes	239.7		16.8	(9.6)	246.9
Income tax provisions (benefits)	45.0		4.1	0.8	49.9
Results of operations (excluding Corporate segment)	$	194.7	12.7	(10.4)	197.0

Three Months Ended June 30, 2020
Oil and gas sales and other operating revenues	$	228.3	59.2	—	287.5
Lease operating expenses	116.8		27.4	0.5	144.7
Severance and ad valorem taxes	6.1		0.4	—	6.5
Transportation, gathering and processing	31.5		9.6	—	41.1
Depreciation, depletion and amortization	175.8		49.7	0.5	226.0
Accretion of asset retirement obligations	9.1		1.3	—	10.4
Impairment of assets	19.6		—	—	19.6
Exploration expenses
Dry holes and previously suspended exploration costs	7.6		—	—	7.6
Geological and geophysical	8.0		0.1	0.5	8.6
Other exploration	2.9		0.1	3.0	6.0
	18.5		0.2	3.5	22.2
Undeveloped lease amortization	4.8		—	2.4	7.2
Total exploration expenses	23.3		0.2	5.9	29.4
Selling and general expenses	7.6		5.4	2.3	15.3
Other	24.2		(1.2)	0.1	23.1
Results of operations before taxes	(185.7)		(33.6)	(9.3)	(228.6)
Income tax provisions (benefits)	(42.6)		(14.1)	(0.3)	(57.0)
Results of operations (excluding Corporate segment)	$	(143.1)	(19.5)	(9.0)	(171.6)

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

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – ~~THREE MONTHS ENDED JUNE 30, 2020 AND 2019~~

(Millions of dollars)
United
States ¹
Canada Other Total
Three Months Ended June 30, 2020
Oil and gas sales and other operating revenues $ 228.3 59.2 — 287.5
Lease operating expenses 116.8 27.4 0.5 144.7
Severance and ad valorem taxes 6.1 0.4 — 6.5
Transportation, gathering and processing 31.5 9.6 — 41.1
Depreciation, depletion and amortization 175.8 49.7 0.5 226.0
Impairments of assets 19.6 — — 19.6
Accretion of asset retirement obligations 9.1 1.3 — 10.4
Exploration expenses
Dry holes and previously suspended exploration costs 7.6 — — 7.6
Geological and geophysical 8.0 0.1 0.5 8.6
Other exploration 2.9 0.1 3.0 6.0
18.5 0.2 3.5 22.2
Undeveloped lease amortization 4.8 — 2.4 7.2
Total exploration expenses 23.3 0.2 5.9 29.4
Selling and general expenses 7.6 5.4 2.3 15.3
Other 24.2 (1.2) 0.1 23.1
Results of operations before taxes (185.7) (33.6) (9.3) (228.6)
Income tax provisions (benefits) (42.6) (14.1) (0.3) (57.0)
Results of operations (excluding Corporate segment) $ (143.1) (19.5) (9.0) (171.6)

Three Months Ended June 30, 2019
Oil and gas sales and other operating revenues $ 576.7 102.0 3.1 681.8
Lease operating expenses 99.7 36.9 0.6 137.2
Severance and ad valorem taxes 12.8 0.3 — 13.1
Transportation, gathering and processing 27.7 7.2 — 34.9
Depreciation, depletion and amortization 201.2 56.8 1.3 259.3
Accretion of asset retirement obligations 8.4 1.5 — 9.9
Exploration expenses
Dry holes and previously suspended exploration costs (0.2) — — (0.2)
Geological and geophysical 15.4 — 2.4 17.8
Other exploration 2.8 0.1 3.1 6.0
18.0 0.1 5.5 23.6
Undeveloped lease amortization 5.9 0.4 0.9 7.2
Total exploration expenses 23.9 0.5 6.4 30.8
Selling and general expenses 12.9 6.1 6.1 25.1
Other 27.9 0.2 0.1 28.2
Results of operations before taxes 162.2 (7.5) (11.4) 143.3
Income tax provisions (benefits) 29.2 (1.6) (8.0) 19.6
Results of operations (excluding Corporate segment) $ 133.0 (5.9) (3.4) 123.7

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

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~OIL AND GAS OPERATING RESULTS –~~ SIX MONTHS ENDED JUNE 30, ~~2020~~2021 AND ~~2019~~2020

~~(Millions of dollars)~~

~~United States~~ ¹

~~Canada~~

~~Other~~

~~Total~~

~~Six Months Ended June 30, 2020~~

~~Oil and gas sales and other operating revenues~~

~~739.8~~

~~148.9~~

~~1.8~~

~~890.5~~

~~Lease operating expenses~~

~~295.0~~

~~58.0~~

~~0.8~~

~~353.8~~

~~Severance and ad valorem taxes~~

~~15.2~~

~~0.7~~

—

~~15.9~~

~~Transportation, gathering and processing~~

~~66.1~~

~~19.4~~

—

~~85.5~~

~~Depreciation, depletion and amortization~~

~~423.3~~

~~101.7~~

~~1.0~~

~~526.0~~

~~Impairment of assets~~

~~947.4~~

—

~~39.7~~

~~987.1~~

~~Accretion of asset retirement obligations~~

~~17.7~~

~~2.7~~

—

~~20.4~~

~~Exploration expenses~~

~~Dry holes and previously suspended exploration costs~~

~~7.7~~

—

~~7.7~~

~~Geological and geophysical~~

~~9.3~~

~~0.1~~

~~4.2~~

~~13.6~~

~~Other exploration~~

~~3.7~~

~~0.3~~

~~9.5~~

~~13.5~~

~~20.7~~

~~0.4~~

~~13.7~~

~~34.8~~

~~Undeveloped lease amortization~~

~~9.9~~

~~0.2~~

~~4.6~~

~~14.7~~

~~Total exploration expenses~~

~~30.6~~

~~0.6~~

~~18.3~~

~~49.5~~

~~Selling and general expenses~~

~~11.3~~

~~9.8~~

~~3.9~~

~~25.0~~

~~Other~~

~~(21.5)~~

~~(1.0)~~

~~(1.1)~~

~~(23.6)~~

~~Results of operations before taxes~~

~~(1,045.3)~~

~~(43.0)~~

~~(60.8)~~

~~(1,149.1)~~

~~Income tax provisions (benefits)~~

~~(206.2)~~

~~(16.6)~~

~~0.5~~

~~(222.3)~~

~~Results of operations (excluding Corporate segment)~~

~~(839.1)~~

~~(26.4)~~

~~(61.3)~~

~~(926.8)~~

~~Six months ended June 30, 2019~~

~~Oil and gas sales and other operating revenues~~

~~1,077.5~~

~~228.9~~

~~6.0~~

~~1,312.4~~

~~Lease operating expenses~~

~~192.1~~

~~75.9~~

~~0.9~~

~~268.9~~

~~Severance and ad valorem taxes~~

~~22.6~~

~~0.6~~

—

~~23.2~~

~~Transportation, gathering and processing~~

~~59.3~~

~~15.2~~

—

~~74.5~~

~~Depreciation, depletion and amortization~~

~~365.1~~

~~116.3~~

~~2.3~~

~~483.7~~

~~Accretion of asset retirement obligations~~

~~16.2~~

~~3.0~~

—

~~19.2~~

~~Exploration expenses~~

~~Dry holes and previously suspended exploration costs~~

~~(0.1)~~

—

~~13.1~~

~~13.0~~

~~Geological and geophysical~~

~~15.9~~

—

~~7.9~~

~~23.8~~

~~Other exploration~~

~~4.0~~

~~0.2~~

~~7.1~~

~~11.3~~

~~19.8~~

~~0.2~~

~~28.1~~

~~48.1~~

~~Undeveloped lease amortization~~

~~12.8~~

~~0.7~~

~~1.7~~

~~15.2~~

~~Total exploration expenses~~

~~32.6~~

~~0.9~~

~~29.8~~

~~63.3~~

~~Selling and general expenses~~

~~30.2~~

~~13.7~~

~~11.7~~

~~55.6~~

~~Other~~

~~58.5~~

~~0.4~~

~~59.3~~

~~Results of operations before taxes~~

~~300.9~~

~~2.9~~

~~(39.1)~~

~~264.7~~

~~Income tax provisions (benefits)~~

~~51.7~~

~~1.3~~

~~(7.4)~~

~~45.6~~

~~Results of operations (excluding Corporate segment)~~

~~249.2~~

~~1.6~~

~~(31.7)~~

~~219.1~~


(Millions of dollars)	United States 1		Canada	Other	Total
Six Months Ended June 30, 2021
Oil and gas sales and other operating revenues	$	1,139.2	224.6	—	1,363.8
Lease operating expenses	206.6		66.6	0.3	273.5
Severance and ad valorem taxes	19.8		0.8	—	20.6
Transportation, gathering and processing	62.1		30.5	—	92.6
Depreciation, depletion and amortization	329.6		88.3	1.0	418.9
Accretion of asset retirement obligations	18.2		4.5	—	22.7
Impairment of assets	—		171.3	—	171.3
Exploration expenses
Dry holes and previously suspended exploration costs	0.6		—	—	0.6
Geological and geophysical	2.7		—	1.0	3.7
Other exploration	2.9		0.1	9.1	12.1
	6.2		0.1	10.1	16.4
Undeveloped lease amortization	4.8		0.1	4.0	8.9
Total exploration expenses	11.0		0.2	14.1	25.3
Selling and general expenses	10.8		8.0	3.5	22.3
Other	94.4		4.0	(3.2)	95.2
Results of operations before taxes	386.7		(149.6)	(15.7)	221.4
Income tax provisions (benefits)	73.0		(38.0)	1.6	36.6
Results of operations (excluding Corporate segment)	$	313.7	(111.6)	(17.3)	184.8

Six months ended June 30, 2020
Oil and gas sales and other operating revenues	$	739.8	148.9	1.8	890.5
Lease operating expenses	295.0		58.0	0.8	353.8
Severance and ad valorem taxes	15.2		0.7	—	15.9
Transportation, gathering and processing	66.1		19.4	—	85.5
Depreciation, depletion and amortization	423.3		101.7	1.0	526.0
Accretion of asset retirement obligations	17.7		2.7	—	20.4
Impairment of assets	947.4		—	39.7	987.1
Exploration expenses
Dry holes and previously suspended exploration costs	7.7		—	—	7.7
Geological and geophysical	9.3		0.1	4.2	13.6
Other exploration	3.7		0.3	9.5	13.5
	20.7		0.4	13.7	34.8
Undeveloped lease amortization	9.9		0.2	4.6	14.7
Total exploration expenses	30.6		0.6	18.3	49.5
Selling and general expenses	11.3		9.8	3.9	25.0
Other	(21.5)		(1.0)	(1.1)	(23.6)
Results of operations before taxes	(1,045.3)		(43.0)	(60.8)	(1,149.1)
Income tax provisions (benefits)	(206.2)		(16.6)	0.5	(222.3)
Results of operations (excluding Corporate segment)	$	(839.1)	(26.4)	(61.3)	(926.8)

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

2827

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

Results of Operations (contd.)

Exploration and Production

Second quarter ~~2020~~2021 vs. ~~2019~~2020

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

United States E&P operations reported earnings of $194.7 million in the second quarter of 2021 compared to a loss of $143.1 million in the second quarter of ~~2020 compared to income of $133.0~~2020. Results were $337.8 million favorable in the ~~second quarter of 2019. Results were $276.1 million unfavorable in the 2020~~2021 quarter compared to the ~~2019~~2020 period due to ~~lower~~higher revenues ($~~348.4~~420.6 million), lower lease operating expenses ($26.3 million), lower impairment charge ($19.6 million), ~~higher lease operating~~and general and administrative expenses ~~($17.1 million) and transportation, gathering, and processing expenses ($3.8~~(G&A: $2.3 million), partially offset by ~~lower~~higher income tax expense ($~~71.8~~87.6 million), other operating expense ($48.7 million) and depreciation, depletion and amortization ($~~25.4 million), general and administrative (G&A: $5.3 million), and other operating expense ($3.7~~4.2 million). ~~Lower~~Higher revenues were primarily due to ~~lower~~higher commodity prices, ~~and lower~~higher Eagle Ford Shale volumes (due to ~~lower~~higher capital expenditures), ~~partially offset by~~and higher volumes in the U.S. Gulf of Mexico ~~(as~~(GOM), due to a ~~result of the LLOG~~3.5% working interest acquisition in the second quarter of 2019 and partially offset by shut-in GOM production in May 2020 due to the low price). The impairment charge relates to a US Offshore project for which the lease expired in June 2020. HigherLucius field. Lower lease operating expense was primarily attributable to well ~~workovers at Dalmatian ($20.5 million) and Cascade 4 ($4.6 million), offset by certain cost-savings initiatives taken~~workers in the ~~US Onshore business.~~GOM in 2020. Lower ~~depreciation~~G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices in 2020). Higher income tax expense ~~was~~is a result of pre-tax profits principally due to the recovering oil price. Higher other operating expense is primarily due to ~~lower depreciation rates following the impairment charges incurred in the first quarter~~unfavorable mark to market revaluation on contingent consideration (as a result of ~~2020.~~higher commodity prices) from prior Gulf of Mexico (GOM) acquisitions.

Canadian E&P operations reported earnings of $12.7 million in the second quarter 2021 compared to a loss of $19.5 million in the second quarter ~~2020 compared to a loss~~ of ~~$5.9 million in the 2019 quarter.~~2020. Results were ~~unfavorable $13.6~~favorable $32.2 million compared to the ~~2019~~2020 period primarily due to ~~lower~~higher revenue ($~~42.8 million), partially offset by a higher tax benefit ($12.5 million), lower lease operating expenses ($9.5~~61.4 million) and lower depreciation and amortization ($~~7.1~~6.2 million)~~. Lower revenue was principally due to lower commodity prices and lower Terra Nova volumes,~~, partially offset by higher tax expense ($18.2 million), higher lease operating expenses ($8.4 million), higher transportation, gathering, and processing expenses ($6.5 million), and lower other operating income ($2.1 million). Higher revenue is primarily attributable to higher natural gas prices at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower depreciation expense is due to lower production volumes at Kaybob ~~and Hibernia. Lower~~Duvernay due to normal well decline. Higher lease operating ~~expenses~~ and ~~depreciation were a result of a shut-in at Terra Nova (starting in December 2019). Terra Nova is~~transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be ~~shut-in for~~utilized by growth at Tupper Montney in the ~~remainder of 2020 for Asset Integrity work.~~future.

Other international E&P operations reported a loss from continuing operations of $10.4 million in the second quarter of 2021 compared to a loss of $9.0 million in the second quarter of ~~2020 compared to a net a loss of $3.4 million in the prior year quarter.~~2020. The result was ~~$5.6~~$1.4 million unfavorable in the ~~2020~~2021 period versus ~~2019~~2020 primarily due higher ~~Brunei prior period revenue.~~exploration expenses and income tax expense.

Six months ~~2020~~2021 vs. ~~2019~~2020

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

United States E&P operations reported earnings of $313.7 million in the first six months of 2021 compared to a loss of $839.1 million in the first six months of ~~2020 compared to income of $249.2~~2020. Results were $1,152.8 million favorable in the ~~first six months of 2019. Results were $1,088.3 million unfavorable in the 2020~~2021 quarter compared to the ~~2019~~2020 period primarily due to anno impairment ~~charge~~charges in the current period (2020: $947.4 million). Further, the change year over year is driven by higher revenues ($~~947.4~~399.4 million), lower ~~revenues ($337.7 million), higher lease operating expenses ($102.9 million),~~ depreciation, depletion and amortization (DD&A: ~~$58.2~~$93.7 million), ~~and~~lower lease operating expenses (LOE: $88.4 million), lower transportation, gathering, and processing charges ($~~6.8~~4.0 million); and lower G&A ($0.5 million), partially offset by ~~lower~~higher income tax expense ($~~257.9~~279.2 million), and higher other operating expense ($~~80.0 million), and G&A ($18.9~~115.9 million). The impairment charge ~~is a~~in the prior year was primarily the result of lower forecast future prices ~~at the end~~as of ~~the first quarter~~March 31, 2020, as a result of decreased oil demand (COVID-19 impact) and ~~increased~~abundant oil supply ~~(as discussed above). Based on an evaluation~~at the time of ~~expected future cash flows from properties as~~the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. Lower DD&A is a result of ~~June 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,~~prior year impairment charge reducing 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. Higherdepreciable asset base. Lower lease operating expenses ~~and depreciation expense~~ were primarily due ~~primarily~~ to higher ~~volumes from the LLOG acquisition~~Gulf of Mexico workover costs in the ~~second quarter of 2019 ($21.9 million) and well workovers~~prior year at Cascade ($49.3 million) and Dalmatian ($20.5 million). ~~Lower~~Higher income tax expense is a result of pre-tax ~~losses driven by~~profits principally due to the ~~impairment charge~~recovering oil price and lower ~~commodity prices. Lower~~DD&A and LOE. Higher other operating expense is primarily due to ~~a favorable~~an unfavorable mark to market revaluation on contingent consideration ($76.7 million; as a result of higher commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($43.5 million). Lower G&A is due to lower long-term incentive charges. Lower revenues were primarily due to lower commodity prices partially offset by higher volumes in the U.S. Gulf of Mexico (as a result of the LLOG acquisition in the second quarter of 2019).acquisitions.

Canadian E&P operations reported a loss of $111.6 million in the first six months of 2021 compared to a loss of $26.4 million in the first six months quarter of ~~2020~~2020. Results were $85.2 million unfavorable compared to the 2020 period primarily due to an impairment charge ($171.3 million) in the current period, partially offset by higher revenue ($75.7 million), higher income tax benefit ($21.4 million), and lower DD&A ($13.4 million). The impairment charge in the current year is due to the status, including agreements with the partners, of ~~$1.6~~operating and production plans at Terra Nova as of June 30, 2021. During the second quarter, partners continued to negotiate on an agreement to restructure the Terra Nova project ownership and renew the asset life extension project. Higher revenue is primarily attributable to higher natural gas prices at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Higher income tax benefit is a result of a higher pre-tax loss driven by the impairment

Table of Contents

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

Results of Operations (contd.)

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

Other international E&P operations reported a loss of $17.3 million in the first six months ~~quarter~~ of ~~2019.~~2021 compared to a loss of $61.3 million in the prior year. Results were ~~unfavorable $28~~$44.0 million favorable compared to the ~~2019~~2020 period primarily due to an impairment charge of $39.7 million in the prior year.

Corporate

Second quarter 2021 vs. 2020

Six months 2021 vs. 2020

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative commodity contracts (typically forward swaps to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $478.8 million in the first six months of 2021 compared to earnings of $99.8 million in the first six months of 2020. The $578.6 million unfavorable variance is primarily due to realized and unrealized losses on forward swap commodity contracts in 2021 compared to gains in 2020 (2021: $440.6 million loss; 2020: $324.8 million gain), and higher interest expense ($50.7 million), partially offset by ~~lower lease operating expense~~higher tax benefits ($~~17.9~~171.9 million), lower DDrestructuring charges ($41.4 million), lower G&A ($14.6 million), and lower DD&A ($5.0 million). Realized and unrealized losses on forward swap commodity contracts are due to higher market (West Texas Intermediate) prices whereby the contract provides the Company with a fixed price. As of June 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $71.80 and for 2022 was $66.38 (versus fixed hedge prices of $42.77 and $44.88, respectively). Interest charges are higher in 2021primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022. Higher income tax benefits are a result of pre-tax loss driven by the higher realized and unrealized losses on forward swap commodity contracts. Lower restructuring charges ~~($17.9 million). Lower revenues were~~and G&A expenditures are due to the 2020 cost reduction efforts which included closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

Production Volumes and Prices

Second quarter 2021 vs. 2020

Total hydrocarbon production from continuing operations averaged 182,050 barrels of oil equivalent per day in the second quarter of 2021, which represented a 1% increase from the 179,506 barrels per day produced in second quarter 2020. The increase in production volumes is principally due to increased production in the U.S. offset by lower production in Canada.

Average crude oil and condensate production from continuing operations was 109,327 barrels per day in the second quarter of 2021 compared to 108,712 barrels per day in the second quarter of 2020. The increase of 615 barrels per day was associated with higher Eagle Ford Shale production (3,267 barrels per day higher at Karnes due to 2021 capital expenditures in this area), higher volumes in the Gulf of Mexico (1,466 barrels per day principally due to a 3.5% working interest acquisition in Lucius field), offset by lower volumes in Canada (4,477 barrels per day lower primarily attributable to Kaybob Duvernay well decline). On a worldwide basis, the Company’s crude oil and condensate prices ~~versus~~averaged $65.57 per barrel in the ~~prior year and a shut-in at Terra Nova~~second quarter 2021 compared to $23.03 per barrel in the 2020 period, an increase of 185% quarter over quarter.

Total production of natural gas liquids (NGL) from continuing operations was 11,252 barrels per day in the second quarter 2021 compared to 11,540 barrels per day in the 2020 period. The average sales price for ~~Asset Integrity work (starting~~U.S. NGL was $22.18 per barrel in ~~December 2019 and expected~~the 2021 quarter compared to ~~continue through 2020 full year). Lower lease operating expenses and lower DD&A were a result of lower sales.~~$7.67 per barrel in 2020. The average sales price for NGL in Canada was $30.63 per barrel in the 2021

Table of Contents

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

Results of Operations (contd.)

~~Other international E&P operations reported a loss~~quarter compared to $13.78 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas production volumes from continuing operations ~~of $61.3~~averaged 369 million ~~in the first six months of 2020 compared to a net loss of $31.7 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.~~

~~Corporate~~

~~Second quarter 2020 vs. 2019~~

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 incomecubic feet per day (MMCFD) in the second quarter 2021 compared to 356 MMCFD in 2020. ~~These costs include severance, relocation, IT costs, pension curtailment, termination charges and~~The increase of 13 MMCFD was a ~~write-off~~result of ~~the right of use asset lease associated with the~~higher volumes in Canada ~~office. Further, the office building in El Dorado and two airplanes are classified as held for sale.~~

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 $151.6 million(8 MMCFD), in the ~~second quarter 2020 compared to net loss~~Gulf of ~~$24.9 million~~Mexico (3 MMCFD) and in the ~~2019 quarter. The $126.7 million unfavorable variance is principally~~Eagle Ford Shale (2 MMCFD). Higher natural gas volumes in Canada are primarily due to ~~2020 mark to market losses on forward swap commodity contracts ($184.5 million) compared to gains on forward contracts ($50.8 million)~~bringing online 10 new wells at Tupper Montney in the second quarter of ~~2019, restructuring charges ($41.4 million) related to~~2021. Higher volumes in the ~~closure~~Gulf of the El Dorado and Calgary offices, offset by higher realized gains on forward commodity contracts ($101.5 million), higher tax credit ($27.4 million), lower interest expense ($15.6 million) and G&A expenses ($8.6 million). Losses in forward swap commodity contractsMexico 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. Lower interest expense isprincipally due to higher ~~borrowings~~natural gas volumes at Lucius and Neidermeyer.

Natural gas prices for the total Company averaged $2.34 per thousand cubic feet (MCF) in the ~~second~~2021 quarter, ~~2019 due to temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the revolver borrowings were repaid~~versus $1.54 per MCF average in the ~~third~~same quarter ~~2019 following~~of 2020. Average natural gas prices in the ~~divestment of~~U.S. and Canada in the ~~Malaysia business).~~quarter were $2.61 and $2.23 per MCF, respectively.

Six months ~~2020~~2021 vs. ~~2019~~

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

~~Production Volumes and Prices~~

~~Second quarter 2020 vs. 2019~~

Total hydrocarbon production from all E&P continuing operations averaged ~~179,506~~173,762 barrels of oil equivalent per day in the ~~second quarter~~first six months of ~~2020,~~2021, which represented a ~~5% increase~~8% decrease from the ~~170,885~~189,350 barrels per day produced in ~~second quarter 2019.~~the first six months of 2020. The ~~increase was~~decrease in production is principally due to ~~the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019, partially offset by GOM shut-in production in May~~lower capital expenditures throughout 2020 ~~(32.4 MBOED) for low commodity prices and lower Eagle Ford Shale production.~~to support generating positive free cashflow.

Average crude oil and condensate production from continuing operations was ~~108,712~~103,434 barrels per day in the ~~second quarter~~first six months of ~~2020~~2021 compared to ~~107,283~~115,396 barrels per day in the ~~second quarter~~first six months of ~~2019.~~2020. The ~~increase~~decrease of ~~1,429~~11,962 barrels per day was principally due to ~~higher volumes in the~~lower Gulf of Mexico ~~(5,940~~production (6,439 barrels per day) due to temporary operational issues at the ~~acquisition~~Cascade & Chinook and Kodiak fields in the first quarter of ~~assets as part of the LLOG acquisition and~~2021 (these operational issues are now resolved), offset by ~~GOM shut-in~~higher second quarter production ~~in May 2020 (20 MBOED) for low commodity prices and lower Eagle Ford Shale production.~~at Lucius. On a worldwide basis, the Company’s crude oil and condensate prices averaged ~~$23.03 per barrel in the second quarter 2020 compared to $64.74 per barrel in the 2019 period, a decrease of 64% quarter to quarter.~~

Total production of natural gas liquids (NGL) from continuing operations was 11,540 barrels per day in the second quarter 2020 compared to 10,168 barrels per day in the 2019 period. The average sales price for U.S. NGL was $7.67 per barrel in the 2020 quarter compared to $15.95 per barrel in 2019. The average sales price for NGL in Canada was $13.78 per barrel in the 2020 quarter compared to $28.41 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 356 million cubic feet per day (MMCFD) in the second quarter 2020 compared to 321 MMCFD in 2019. The increase of 35 MMCFD was a result of higher volumes in the Gulf of Mexico (30 MMCFD) and higher volumes in Canada (10 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.

Natural gas prices for the total Company averaged $1.54 per thousand cubic feet (MCF) in the 2020 quarter, versus $1.55 per MCF average in the same quarter of 2019. Average natural gas prices in the US and Canada in the quarter were $1.68 and $1.49 respectively.

~~Six months 2020 vs. 2019~~

Total hydrocarbon production from all E&P continuing operations averaged 189,350 barrels of oil equivalent per day in the first six months of 2020, which represented a 14% increase from the 166,269 barrels per day produced in the first six 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 115,396 barrels per day in the first six months of 2020 compared to 104,567 barrels per day in the first six months of 2019. The increase of 10,829 barrels per day was principally due to higher volumes in the Gulf of Mexico (11,811 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 $35.65$62.14 per barrel in the first six months of ~~2020~~2021 compared to ~~$61.83~~$35.65 per barrel in the ~~2019~~2020 period, ~~a decrease~~an increase of ~~42%~~74% year over year.

Total production of natural gas liquids (NGL) from continuing operations was ~~12,597~~10,552 barrels per day in the first six months of ~~2020~~2021 compared to ~~9,664~~12,597 barrels per day in the ~~2019~~2020 period. The average sales price for U.S. NGL was $22.41 per barrel in 2021 compared to $8.62 per barrel in ~~2020 compared to $17.20 per barrel in 2019.~~2020. The average sales price for NGL in Canada was $33.34 per barrel in 2021 compared to $15.04 per barrel in ~~2020 compared to $31.81 per barrel in 2019.~~2020. NGL prices are higher in Canada due to the higher value of the product ~~produced~~ at the Kaybob Duvernay and Placid Montney assets.

Natural gas sales volumes from continuing operations averaged ~~368~~359 million cubic feet per day (MMCFD) in the first six months of ~~2020~~2021 compared to ~~312~~368 MMCFD in ~~2019.~~2020. The ~~increase~~decrease of 569 MMCFD was ~~a primarily~~ the result of ~~higher~~lower volumes in Eagle Ford (4 MMCFD), the Gulf of Mexico ~~(46~~(3 MMCFD) and ~~the Canadian Tupper asset (20~~Canada (2 MMCFD). ~~Higher~~Lower volumes in the Gulf of Mexico are principally due to ~~the acquisition of assets related to the LLOG transaction. Higher volumes~~temporary operational issues at the ~~Tupper asset~~Cascade & Chinook and Kodiak fields (these operational issues are now resolved). Lower volumes in Canada and Eagle Ford Shale are due to ~~higher number~~normal well decline, lower capital expenditures throughout 2020 and the effects of ~~wells operating and improved type curves.~~a winter storm impacting the Eagle Ford Shale in the first quarter of 2021.

Natural gas prices for the total Company averaged ~~$1.64~~$2.44 per thousand cubic feet (MCF) in the first six months of ~~2020,~~2021, versus ~~$1.88~~$1.64 per MCF average in the same period of ~~2019.~~2020. Average natural gas prices in the USU.S. and Canada in the quarter were ~~$1.84~~$2.97 and ~~$1.55,~~$2.25, respectively.

Additional details about results of oil and natural gas operations are presented in the tables on pages 2726 and ~~28.~~27.

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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 six-month periods ended June 30, ~~2020~~2021 and ~~2019.~~2020.


			Three Months Ended June 30,						Six Months Ended June 30,								Three Months Ended June 30,				Six Months Ended June 30,
Barrels per day unless otherwise noted	Barrels per day unless otherwise noted			2020		2019		2020		2019		Barrels per day unless otherwise noted		2021		2020		2021		2020
Continuing operations	Continuing operations									Continuing operations
Net crude oil and condensate	Net crude oil and condensate											Net crude oil and condensate
United States	United States	Onshore	27,986		33,145		29,510		29,532	United States	Onshore		31,253		27,986		26,734		29,510
		Gulf of Mexico ¹	67,002		61,062		72,866		61,055		Gulf of Mexico 1		68,468		67,002		66,427		72,866
Canada	Canada	Onshore	7,872		5,943		7,353		6,199	Canada	Onshore		5,558		7,872		5,921		7,353
		Offshore	5,852		6,685		5,495		7,304		Offshore		3,689		5,852		4,137		5,495
Other	Other		—		448		172		477	Other			359		—		215		172
Total net crude oil and condensate - continuing operations	Total net crude oil and condensate - continuing operations			108,712		107,283		115,396		104,567		Total net crude oil and condensate - continuing operations		109,327		108,712		103,434		115,396
Net natural gas liquids	Net natural gas liquids									Net natural gas liquids
United States	United States	Onshore	5,303		5,977		5,444		5,641	United States	Onshore		5,327		5,303		4,634		5,444
		Gulf of Mexico ¹	5,219		3,118		5,944		2,940		Gulf of Mexico 1		4,763		5,219		4,721		5,944
Canada	Canada	Onshore	1,018		1,073		1,209		1,083	Canada	Onshore		1,162		1,018		1,197		1,209
Total net natural gas liquids - continuing operations	Total net natural gas liquids - continuing operations			11,540		10,168		12,597		9,664		Total net natural gas liquids - continuing operations		11,252		11,540		10,552		12,597
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	27,697		32,209		29,830		30,752	United States	Onshore		29,653		27,697		25,855		29,830
		Gulf of Mexico ¹	68,717		39,029		75,333		29,356		Gulf of Mexico 1		71,962		68,717		72,308		75,333
Canada	Canada	Onshore	259,108		249,367		262,978		252,120	Canada	Onshore		267,210		259,108		260,491		262,978
Total net natural gas - continuing operations	Total net natural gas - continuing operations			355,522		320,605		368,141		312,228		Total net natural gas - continuing operations		368,825		355,522		358,654		368,141
Total net hydrocarbons - continuing operations including NCI ^2,3	Total net hydrocarbons - continuing operations including NCI ^2,3			179,506		170,885		189,350		166,269		Total net hydrocarbons - continuing operations including NCI 2,3		182,050		179,506		173,762		189,350
Noncontrolling interest	Noncontrolling interest									Noncontrolling interest
Net crude oil and condensate – barrels per day	Net crude oil and condensate – barrels per day			(10,719)		(11,160)		(11,370)		(11,669)		Net crude oil and condensate – barrels per day		(9,800)		(10,719)		(9,489)		(11,370)
Net natural gas liquids – barrels per day	Net natural gas liquids – barrels per day			(443)		(458)		(501)		(506)		Net natural gas liquids – barrels per day		(370)		(443)		(362)		(501)
Net natural gas – thousands of cubic feet per day	Net natural gas – thousands of cubic feet per day			(4,059)		(4,507)		(4,575)		(4,203)		Net natural gas – thousands of cubic feet per day		(4,024)		(4,059)		(4,091)		(4,575)
Total noncontrolling interest	Total noncontrolling interest			(11,839)		(12,369)		(12,634)		(12,876)		Total noncontrolling interest		(10,841)		(11,839)		(10,533)		(12,634)
Total net hydrocarbons - continuing operations excluding NCI ^2,3	Total net hydrocarbons - continuing operations excluding NCI ^2,3			167,667		158,516		176,716		153,394		Total net hydrocarbons - continuing operations excluding NCI 2,3		171,209		167,667		163,229		176,716
Discontinued operations
Net crude oil and condensate – barrels per day				—		21,556		—		23,744
Net natural gas liquids – barrels per day				—		529		—		636
Net natural gas – thousands of cubic feet per day ²				—		93,382		—		97,465
Total discontinued operations				—		37,649		—		40,624
Total net hydrocarbons produced excluding NCI ^2,3				167,667		196,165		176,716		194,018

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

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

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

~~Table of Contents~~

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

~~Results of Operations (contd.)~~

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

Three Months Ended
June 30, Six Months Ended
June 30,
Barrels per day unless otherwise noted 2020 2019 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 27,986 33,145 29,510 29,532
Gulf of Mexico ¹
66,669 58,842 73,836 61,053
Canada Onshore 7,872 5,943 7,353 6,199
Offshore 5,943 6,723 5,559 7,324
Other — 470 156 468
Total net crude oil and condensate - continuing operations 108,470 105,123 116,414 104,576
Net natural gas liquids
United States Onshore 5,303 5,977 5,444 5,641
Gulf of Mexico ¹
5,219 3,118 5,944 2,940
Canada Onshore 1,018 1,073 1,209 1,083
Total net natural gas liquids - continuing operations 11,540 10,168 12,597 9,664
Net natural gas – thousands of cubic feet per day
United States Onshore 27,697 32,209 29,830 30,752
Gulf of Mexico ¹
68,717 39,029 75,333 29,356
Canada Onshore 259,108 249,367 262,978 252,120
Total net natural gas - continuing operations 355,522 320,605 368,141 312,228
Total net hydrocarbons - continuing operations including NCI ^2,3
179,264 168,725 190,368 166,278
Noncontrolling interest
Net crude oil and condensate – barrels per day (10,653) (10,715) (11,564) (11,669)
Net natural gas liquids – barrels per day (443) (458) (501) (506)
Net natural gas – thousands of cubic feet per day²
(4,059) (4,507) (4,575) (4,203)
Total noncontrolling interest (11,773) (11,924) (12,828) (12,876)
Total net hydrocarbons - continuing operations excluding NCI ^2,3
167,491 156,801 177,540 153,403
Discontinued operations
Net crude oil and condensate – barrels per day — 21,121 — 23,676
Net natural gas liquids – barrels per day — 498 — 580
Net natural gas – thousands of cubic feet per day²
— 93,382 — 97,465
Total discontinued operations — 37,183 — 40,500
Total net hydrocarbons sold excluding NCI ^2,3
167,491 193,984 177,540 193,903

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

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

³NCI – noncontrolling interest in MP GOM.

3331

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 six-month periods ended June 30, ~~2020~~2021 and ~~2019.~~2020.໿ Comparative periods are conformed to current presentation.


			Three Months Ended June 30,			Six Months Ended June 30,						Three Months Ended June 30,		Six Months Ended June 30,
			2020	2019	2020	2019				2021	2020	2021	2020
Weighted average Exploration and Production sales prices	Weighted average Exploration and Production sales prices								Weighted average Exploration and Production sales prices
Continuing operations	Continuing operations						Continuing operations
Crude oil and condensate – dollars per barrel	Crude oil and condensate – dollars per barrel								Crude oil and condensate – dollars per barrel
United States	United States	Onshore	21.42	64.17	34.59	61.41	United States	Onshore		64.55	21.42	61.60	34.59
		Gulf of Mexico ¹	24.77	65.79	37.00	62.62		Gulf of Mexico 1		65.95	24.77	62.56	37.00
Canada ²	Canada ²	Onshore	16.09	51.83	26.09	50.78	Canada 2	Onshore		60.69	16.09	56.55	26.09
		Offshore	20.48	69.23	35.28	65.84		Offshore		73.20	20.48	67.51	35.28
Other	Other		—	73.05	63.51	70.50	Other			—	—	—	63.51
Natural gas liquids – dollars per barrel	Natural gas liquids – dollars per barrel								Natural gas liquids – dollars per barrel
United States	United States	Onshore	8.03	15.98	9.45	16.55	United States	Onshore		19.75	8.03	20.38	9.45
		Gulf of Mexico ¹	7.29	15.78	7.85	18.36		Gulf of Mexico 1		24.84	7.29	24.36	7.85
Canada ²	Canada ²	Onshore	13.78	28.41	15.04	31.81	Canada 2	Onshore		30.63	13.78	33.34	15.04
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	1.62	2.50	1.74	2.68	United States	Onshore		2.54	1.62	2.84	1.74
		Gulf of Mexico ¹	1.71	2.60	1.87	2.58		Gulf of Mexico 1		2.64	1.71	3.01	1.87
Canada ²	Canada ²	Onshore	1.49	1.26	1.55	1.71	Canada 2	Onshore		2.23	1.49	2.25	1.55
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia ³		Sarawak	—	78.25	—	70.32
		Block K	—	65.79	—	65.56
Natural gas liquids – dollars per barrel
Malaysia ³		Sarawak	—	41.45	—	48.07
Natural gas – dollars per thousand cubic feet
Malaysia ³		Sarawak	—	2.57	—	3.60
		Block K	—	0.24	—	0.24

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

²U.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 ~~$369.4~~$686.3 million for the first six months of ~~2020~~2021 compared to ~~$655.4~~$369.4 million during the same period in ~~2019.~~2020. The ~~decreased~~increased cash from operating activities is primarily attributable to ~~lower~~higher revenue from sales to customers ($~~423.5~~465.1 million) ~~and higher~~, lower lease operating ~~expenses~~expense ($~~85.0~~80.2 million), lower working capital ($25.2 million), and lower general and administrative expense ($17.3 million), partially offset by higher cash payments ~~received~~made on forward swap commodity contracts ~~($143.9~~(2021: realized loss of $156.3 million; 2020: realized gain of $150.9 million)~~, lower general and administrative expenses ($45.0 million)~~. ~~See above for explanation of underlying business reasons.~~

Cash ~~Used in~~Required by Investing Activities

~~Cash used~~Net cash required by investing activities was $193.7 million for ~~property~~the first six months of 2021 compared to $589.2 million during the same period in 2020. Property additions and dry ~~holes,~~hole costs, which includes amounts expensed, were ~~$589.2~~$463.0 million and ~~$645.2~~$589.2 million in the ~~six-month periods ended June 30,~~first six months of 2021 and 2020, ~~and 2019,~~ respectively. ~~In 2020, this includes~~These amounts include $17.7 million and $51.6 million used to fund the development of the King’s Quay FPS in the first six months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which ~~is expected to be refunded on~~reimburses the ~~closing of a transaction to sell this asset to a third party.~~Company for previously incurred capital expenditures. Lower property additions in 2021 are ~~a result of reducing the~~principally due to lower capital spending ~~budget in response to the current commodity price environment.~~at Eagle Ford Shale and lower spend on King’s Quay.

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

Financial Condition (contd.)

As a result of the lower commodity prices, the Company has made significant reductions to its planned 2020 capital spending for the remainder of 2020. See Outlook section on page 36 for further details.

Total accrual basis capital expenditures were as follows:


		Six Months Ended June 30,						Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	2020		2019	(Millions of dollars)	2021		2020
Capital Expenditures	Capital Expenditures				Capital Expenditures
Exploration and production	Exploration and production	$	550.2	1,966.9	Exploration and production	$	449.4	550.2
Corporate	Corporate	7.4		5.6	Corporate	8.8		7.4
Total capital expenditures	Total capital expenditures	$	557.6	1,972.5	Total capital expenditures	$	458.2	557.6

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


		Six Months Ended June 30,						Six Months Ended June 30,
(Millions of dollars)	(Millions of dollars)	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	$	537.6	645.2	Property additions and dry hole costs per cash flow statements	$	445.3	537.6
Property additions King's Quay per cash flow statements	Property additions King's Quay per cash flow statements	51.6		—	Property additions King's Quay per cash flow statements	17.7		51.6
Acquisition of oil and gas properties		—		1,226.3

Geophysical and other exploration expenses	Geophysical and other exploration expenses	23.0		32.0	Geophysical and other exploration expenses	12.4		23.0
Capital expenditure accrual changes and other	Capital expenditure accrual changes and other	(54.6)		69.0	Capital expenditure accrual changes and other	(17.2)		(54.6)
Total capital expenditures	Total capital expenditures	$	557.6	1,972.5	Total capital expenditures	$	458.2	557.6

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

Cash Used in/ Provided by Financing Activities

Net cash ~~provided~~required by financing activities was ~~$60.0~~$386.7 million for the first six months of ~~2020~~2021 compared to net cash provided by financing activities of ~~$1,113.5~~$60.0 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 (make whole payment) of the notes due 2022 ($34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($75.2 million), and cash dividends to shareholders ($38.6 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).

As of June 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,569.0 million available on its committed RCF.

In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured ~~RCF~~revolving credit facility ($~~170.0~~370.0 million)~~. Total~~, offset by repayments on the revolving credit facility ($200.0 million), cash dividends to shareholders ~~amounted~~($57.6 million), and distributions to ~~$57.6 million for~~ the six months ended June 30, 2020 compared to $85.5 million in the same period of 2019 due to shares repurchased throughout 2019 and a 50% reduction in the quarterly dividend effective in the second quarter 2020. As of June 30, 2020 and in the event it is required to fund investing activities from borrowings, the Company has $1,426.3 million available on its committed RCF.

~~In 2019, net cash provided by financing activities was $1.1 billion principally from net borrowings on the RCF~~NCI ($~~1,075.0~~32.4 million) and a short-term loan ($500.0 million) to fund the LLOG acquisition. These borrowings were repaid in July 2019 following the completion of the Malaysia divestment for net sales proceeds of $2.0 billion. In 2019 the Company used cash to buy back issued ordinary shares of $299.9 million..

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at June 30, ~~2020~~2021 was ~~$(18.0)~~a deficit of $395.5 million, ~~$61.1~~$366.1 million ~~higher~~lower than December 31, ~~2019,~~2020, with the ~~increase~~decrease primarily attributable to ~~a lower cash balance ($161.3 million), lower~~higher accounts payable ($~~235.9~~337.0 million), ~~lower accounts receivable ($54.1 million), and lower~~higher other accrued liabilities ($~~45.6~~170.9 million), higher operating lease liabilities ($63.7 million), partly offset by a higher cash balance ($107.5 million) and higher accounts receivable ($104.5 million). ~~Lower~~Higher accounts payable is primarily due to ~~lower capital activity. Lower accounts receivable is~~the increase in unrealized losses on crude contracts maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 GOM acquisitions) and short-term abandonment liabilities associated with Terra Nova and Cottonwood assets. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS.

Capital Employed

At June 30, 2021, long-term debt of $2,762.9 million had decreased by $225.2 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due ~~to lower commodity sales prices.~~2022 ($576.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.

3533

Table of Contents

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

Financial Condition (contd.)

~~Capital Employed~~

At June 30, 2020, long-term debt of $2,956.4 million had increased by $153.0 million compared to December 31, 2019, as a result of net borrowing on the RCF. The fixed-rate notes had a weighted average maturity of 7.3 years and a weighted average coupon of 5.9 percent.

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


		June 30, 2020						December 31, 2019							June 30, 2021				December 31, 2020
(Millions of dollars)	(Millions of dollars)	Amount		%		Amount		%		(Millions of dollars)	Amount		%		Amount		%
Capital employed	Capital employed									Capital employed
Long-term debt	Long-term debt	$	2,956.4	39.3	%	$	2,803.4	33.9	%	Long-term debt	$	2,762.9	41.6	%	$	2,988.1	41.5	%
Murphy shareholders' equity	Murphy shareholders' equity	4,568.5		60.7	%	5,467.5		66.1	%	Murphy shareholders' equity	3,880.6		58.4	%	4,214.3		58.5	%
Total capital employed	Total capital employed	$	7,525.0	100.0	%	$	8,270.8	100.0	%	Total capital employed	$	6,643.5	100.0	%	$	7,202.4	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. At June 30, ~~2020,~~2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$20.5~~$121.9 million in ~~Canada. In addition, $19.1~~Canada and $8.4 million ~~of cash was held~~ in ~~the United Kingdom and $11.8 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at June 30, 2020).~~Brunei. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

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

Outlook

As discussed in the Summary section on page ~~24,~~23, average crude oil prices ~~were lower~~continued to recover during the second quarter of ~~2020 compared to~~2021 versus the ~~average prices during the first~~second quarter of ~~2020.~~2020 (Q2 2020 WTI: $27.85; Q2 2021 WTI: $66.07). As of close on August 3, 2021, the NYMEX WTI forward curve ~~prices~~price for the ~~balance~~remainder of ~~2020 have recovered to an average of $42.07~~2021 and 2022 were $69.71 and $65.34 per barrel, ~~at the end of July 2020,~~respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and ~~other economic factors~~OPEC+ decisions) may have on future commodity pricing. Lower prices, ~~are expected to~~should they occur, will result in lower profits and operating cash-flows. For the third quarter, production is expected to average between ~~153~~162 and ~~163~~170 MBOEPD, excluding NCI. ~~If price volatility persists, the Company~~

The Company’s capital expenditure spend for 2021 is expected to be between $685.0 million and $715.0 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 ~~is closely monitoring~~plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt. In the third quarter of 2021, the Company announced the redemption of $150.0 million in aggregate principal amount of its 6.875% notes due 2024.

The Company continues to monitor the impact of ~~lower~~ commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The ~~Company’s response~~Company continues to monitor the effects of the COVID-19 pandemic and is ~~discussed in more detail in~~encouraged by the ~~risk factors on page 39.~~ 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 August ~~5, 2020,~~3, 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

Price
(USD/Bbl)

Start Date

End Date

United States

WTI ¹

Fixed price derivative swap

45,000

$56.42

7/1/2020

12/31/2020

United States

WTI ¹

Fixed price derivative swap

45,000

$42.77

7/1/2021

United States

WTI ¹

Fixed price derivative swap

15,000

$42.93

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

Table of Contents

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

Volumes
(MMcf/d)

Price
(CAD/Mcf)

Remaining Period

Area

Commodity

Type

Start Date

End Date

Montney

Natural Gas

Fixed price forward sales at AECO

241

C$~~2.81~~2.57

7/1/~~2020~~2021

12/31/~~2020~~2021

Montney

Natural Gas

Fixed price forward sales at AECO

231

C$~~2.62~~2.42

1/1/~~2021~~2022

1/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

221

C$2.41

2/1/2022

4/30/2022

Montney

Natural Gas

Fixed price forward sales at AECO

250

C$2.40

5/1/2022

5/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

292

C$2.39

6/1/2022

10/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

311

C$2.40

11/1/2022

12/31/~~2021~~2022

Montney

Natural Gas

Fixed price forward sales at AECO

294

C$2.38

1/1/2023

3/31/2023

Montney

Natural Gas

Fixed price forward sales at AECO

275

C$2.37

4/1/2023

12/31/2023

Montney

Natural Gas

Fixed price forward sales at AECO

185

C$2.41

1/1/2024

12/31/2024

¹ ~~West Texas Intermediate~~

~~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 3937 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There were commodity transactions in place at June 30, ~~2020,~~2021, covering certain future U.S. crude oil sales volumes in ~~2020.~~2021 and 2022. A 10% increase in the respective benchmark price of these commodities would have ~~decreased~~increased the net ~~receivable~~payable associated with these derivative contracts by approximately ~~$35.7~~$106.9 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 June 30, ~~2020.~~2021.

ITEM 4. CONTROLS AND PROCEDURES

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

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

During the quarter ended June 30, ~~2020,~~2021, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Table of Contents

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its ~~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:

•~~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;~~

•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;

•~~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.~~

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 in May and June 2020.

Further, the recent global downturn, largely triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon 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.

For the three months ended June 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $28 (compared to $46 in the first three months of 2020). The closing price for WTI at the end of the second quarter of 2020 was approximately $38 per barrel (compared to $30 at the end of the first quarter), reflecting a 36% 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 August 4, 2020 closing, the NYMEX WTI forward curve price for September through December 2020 was $42.07. 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.

The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended June 30, 2020 was $1.65 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of June 30, 2020, was $1.57 per MMBTU. In comparison, NYMEX was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017 The

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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 $1.33 per MMBTU in 2019. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 41 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 during 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. 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 the first half of 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

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

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~~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 4339 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

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SIGNATURE

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


			MURPHY OIL CORPORATION
			(Registrant)

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

August ~~6, 2020~~5, 2021

(Date)

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EXHIBIT INDEX

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


Exhibit No.		Incorporated by Reference to the Indicated Filing by Murphy Oil Corporation

~~3.2~~10.26	~~By-Laws of~~ Murphy Oil Corporation ~~as amended effective August 5, 2020~~2021 Stock Plan for Non-Employee Directors
	Exhibit A to definitive proxy statement filed March 26, 2021
*10.27	~~31.1~~Form of non-employee director restricted stock unit award – stock settled grant agreement (2021 NED Plan)
*31.1	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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

*32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS	XBRL Instance Document

101. SCH	XBRL Taxonomy Extension Schema Document

101. CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF	XBRL Taxonomy Extension Definition Linkbase Document

101. LAB	XBRL Taxonomy Extension Labels Linkbase Document

101. PRE	XBRL Taxonomy Extension Presentation Linkbase

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

4339


(Millions of dollars)	United States ¹		Canada	Other	Total
Three Months Ended June 30, 2020
Oil and gas sales and other operating revenues	$	228.3	59.2	—	287.5
Lease operating expenses	116.8		27.4	0.5	144.7
Severance and ad valorem taxes	6.1		0.4	—	6.5
Transportation, gathering and processing	31.5		9.6	—	41.1
Depreciation, depletion and amortization	175.8		49.7	0.5	226.0
Impairments of assets	19.6		—	—	19.6
Accretion of asset retirement obligations	9.1		1.3	—	10.4
Exploration expenses
Dry holes and previously suspended exploration costs	7.6		—	—	7.6
Geological and geophysical	8.0		0.1	0.5	8.6
Other exploration	2.9		0.1	3.0	6.0
	18.5		0.2	3.5	22.2
Undeveloped lease amortization	4.8		—	2.4	7.2
Total exploration expenses	23.3		0.2	5.9	29.4
Selling and general expenses	7.6		5.4	2.3	15.3
Other	24.2		(1.2)	0.1	23.1
Results of operations before taxes	(185.7)		(33.6)	(9.3)	(228.6)
Income tax provisions (benefits)	(42.6)		(14.1)	(0.3)	(57.0)
Results of operations (excluding Corporate segment)	$	(143.1)	(19.5)	(9.0)	(171.6)

Three Months Ended June 30, 2019
Oil and gas sales and other operating revenues	$	576.7	102.0	3.1	681.8
Lease operating expenses	99.7		36.9	0.6	137.2
Severance and ad valorem taxes	12.8		0.3	—	13.1
Transportation, gathering and processing	27.7		7.2	—	34.9
Depreciation, depletion and amortization	201.2		56.8	1.3	259.3
Accretion of asset retirement obligations	8.4		1.5	—	9.9
Exploration expenses
Dry holes and previously suspended exploration costs	(0.2)		—	—	(0.2)
Geological and geophysical	15.4		—	2.4	17.8
Other exploration	2.8		0.1	3.1	6.0
	18.0		0.1	5.5	23.6
Undeveloped lease amortization	5.9		0.4	0.9	7.2
Total exploration expenses	23.9		0.5	6.4	30.8
Selling and general expenses	12.9		6.1	6.1	25.1
Other	27.9		0.2	0.1	28.2
Results of operations before taxes	162.2		(7.5)	(11.4)	143.3
Income tax provisions (benefits)	29.2		(1.6)	(8.0)	19.6
Results of operations (excluding Corporate segment)	$	133.0	(5.9)	(3.4)	123.7