mur-20210630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2021


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

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


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

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


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

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2021 was 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			14
Note J – Earnings Per Share			16
Note K – Income Taxes			16
Note L – Financial Instruments and Risk Management			17
Note M – Accumulated Other Comprehensive Loss			19
Note N – Environmental and Other Contingencies			19
Note O – Business Segments			20
Note P – Leases			21


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23




Item 3. Quantitative and Qualitative Disclosures About Market Risk			36
Item 4. Controls and Procedures			36
Part II – Other Information			37
Item 1. Legal Proceedings			37
Item 1A. Risk Factors			37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 6. Exhibits			37
Signature			38

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)


(Thousands of dollars)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	418,100	310,606
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020	366,542		262,014
Inventories	57,116		66,076
Prepaid expenses	36,027		33,860
Assets held for sale	40,821		327,736
Total current assets	918,606		1,000,292
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	973,801		927,658
Deferred income taxes	457,600		395,253
Deferred charges and other assets	29,645		28,611

Total assets	$	10,604,190	10,620,852
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	755	—
Accounts payable	744,067		407,097
Income taxes payable	19,176		18,018
Other taxes payable	20,290		22,498
Operating lease liabilities	167,474		103,758
Other accrued liabilities	321,524		150,578
Liabilities associated with assets held for sale	—		14,372
Total current liabilities	1,273,286		716,321
Long-term debt, including finance lease obligation	2,762,851		2,988,067
Asset retirement obligations	817,502		816,308
Deferred credits and other liabilities	738,407		680,580
Non-current operating lease liabilities	826,713		845,088
Deferred income taxes	143,603		180,341

Total liabilities	6,562,362		6,226,705
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2021 and 195,100,628 shares in 2020	195,101		195,101
Capital in excess of par value	915,181		941,692
Retained earnings	4,980,428		5,369,538
Accumulated other comprehensive loss	(553,519)		(601,333)
Treasury stock	(1,656,591)		(1,690,661)
Murphy Shareholders' Equity	3,880,600		4,214,337
Noncontrolling interest	161,228		179,810
Total equity	4,041,828		4,394,147
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,
(Thousands of dollars, except per share amounts)	2021		2020	2021		2020
Revenues and other income
Revenue from sales to customers	$	758,829	285,745	$	1,351,356	886,303
(Loss) gain on crude contracts	(226,245)		(75,880)	(440,630)		324,792
Gain on sale of assets and other income	17,059		1,677	18,902		4,175
Total revenues and other income	549,643		211,542	929,628		1,215,270
Costs and expenses
Lease operating expenses	126,413		144,644	273,577		353,792
Severance and ad valorem taxes	11,314		6,442	20,545		15,864
Transportation, gathering and processing	49,696		41,090	92,608		85,457
Exploration expenses, including undeveloped lease amortization	13,543		29,468	25,323		49,594
Selling and general expenses	29,113		39,100	58,616		75,872
Restructuring expenses	—		41,397	—		41,397
Depreciation, depletion and amortization	227,288		231,446	425,566		537,548
Accretion of asset retirement obligations	12,164		10,469	22,656		20,435
Impairment of assets	—		19,616	171,296		987,146
Other expense (benefit)	70,328		22,007	91,407		(23,181)
Total costs and expenses	539,859		585,679	1,181,594		2,143,924
Operating income (loss) from continuing operations	9,784		(374,137)	(251,966)		(928,654)
Other income (loss)
Interest income and other (loss)	(4,525)		(5,171)	(9,866)		(4,930)
Interest expense, net	(43,374)		(38,598)	(131,474)		(79,695)
Total other loss	(47,899)		(43,769)	(141,340)		(84,625)
Loss from continuing operations before income taxes	(38,115)		(417,906)	(393,306)		(1,013,279)
Income tax benefit	(11,177)		(94,773)	(99,336)		(186,306)
Loss from continuing operations	(26,938)		(323,133)	(293,970)		(826,973)
(Loss) income from discontinued operations, net of income taxes	(102)		(1,267)	106		(6,129)
Net loss including noncontrolling interest	(27,040)		(324,400)	(293,864)		(833,102)
Less: Net income (loss) attributable to noncontrolling interest	36,042		(7,216)	56,656		(99,814)
NET LOSS ATTRIBUTABLE TO MURPHY	$	(63,082)	(317,184)	$	(350,520)	(733,288)
LOSS PER COMMON SHARE – BASIC
Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)
Discontinued operations	—		(0.01)	—		(0.04)
Net loss	$	(0.41)	(2.06)	$	(2.27)	(4.78)
LOSS PER COMMON SHARE – DILUTED
Continuing operations	$	(0.41)	(2.05)	$	(2.27)	(4.74)
Discontinued operations	—		(0.01)	—		(0.04)
Net loss	$	(0.41)	(2.06)	$	(2.27)	(4.78)
Cash dividends per Common share	0.125		0.125	0.250		0.375

Average Common shares outstanding (thousands)
Basic	154,395		153,581	154,153		153,429
Diluted	154,395		153,581	154,153		153,429

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)


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

Other comprehensive (loss) income	22,091		11,643	47,814		(116,180)
COMPREHENSIVE (LOSS)	$	(4,949)	(312,757)	$	(246,050)	(949,282)

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


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

Mark to market loss (gain) on contingent consideration	76,677		(43,529)
Mark to market loss (gain) on crude contracts	284,360		(173,848)
Long-term non-cash compensation	25,318		22,760
Net (increase) decrease in noncash working capital	26,565		1,335
Other operating activities, net	39,494		(27,605)
Net cash provided by continuing operations activities	686,282		369,379
Investing Activities
Property additions and dry hole costs	(445,314)		(537,601)
Property additions for King's Quay FPS	(17,734)		(51,635)

Proceeds from sales of property, plant and equipment	269,363		—
Net cash (required) by investing activities	(193,685)		(589,236)
Financing Activities
Borrowings on revolving credit facility	165,000		370,000
Repayment of revolving credit facility	(365,000)		(200,000)
Retirement of debt	(576,358)		(12,225)
Debt issuance, net of cost	541,974		(613)
Early redemption of debt cost	(34,177)		—
Distributions to noncontrolling interest	(75,238)		(32,400)
Cash dividends paid	(38,590)		(57,590)
Withholding tax on stock-based incentive awards	(3,895)		(7,247)
Proceeds from term loan and other loans	—		371
Capital lease obligation payments	(371)		(336)

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

Effect of exchange rate changes on cash and cash equivalents	1,552		(1,358)
Net increase (decrease) in cash and cash equivalents	107,494		(161,255)
Cash and cash equivalents at beginning of period	310,606		306,760
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.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)


	Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	2021		2020	2021		2020
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	—	—	$	—	—
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2021 and 195,100,628 shares at June 30, 2020
Balance at beginning of period	195,101		195,101	195,101		195,089
Exercise of stock options	—		—	—		12
Balance at end of period	195,101		195,101	195,101		195,101
Capital in Excess of Par Value
Balance at beginning of period	914,303		924,930	941,692		949,445
Exercise of stock options, including income tax benefits	(587)		—	(626)		(156)
Restricted stock transactions and other	(5,347)		(636)	(38,347)		(33,240)
Share-based compensation	6,812		7,135	12,462		15,380

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


Cash dividends	(19,303)		(19,198)	(38,590)		(57,590)
Balance at end of period	4,980,428		5,823,426	4,980,428		5,823,426
Accumulated Other Comprehensive Loss
Balance at beginning of period	(575,610)		(701,984)	(601,333)		(574,161)
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	4,146		(39,234)	8,282		(48,945)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	—		309	1,690		608

Balance at end of period	(553,519)		(690,341)	(553,519)		(690,341)
Treasury Stock
Balance at beginning of period	(1,661,416)		(1,691,706)	(1,690,661)		(1,717,217)

Awarded restricted stock, net of forfeitures	4,339		636	33,545		26,147
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	(1,656,591)		(1,691,070)	(1,656,591)		(1,691,070)
Murphy Shareholders’ Equity	3,880,600		4,568,545	3,880,600		4,568,545
Noncontrolling Interest
Balance at beginning of period	164,418		212,154	179,810		337,151

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

See Notes to Consolidated Financial Statements, page 7.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note A – Nature of Business and Interim Financial Statements

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

In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) acquisition, we hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2021, our maximum exposure to loss was $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, 2021 and December 31, 2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2021 and 2020, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

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

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

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

Recent Accounting Pronouncements

None affecting the Company.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

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

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

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

Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the Offshore 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Disaggregation of Revenue

The Company reviews performance based on two 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, 2021, the Company recognized $758.8 million and $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, 2020, the Company recognized $285.7 million and $886.3 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.


		Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)		2021		2020	2021	2020
Net crude oil and condensate revenue
United States	Onshore	$	183,267	54,550	297,757	185,786
	Offshore	411,076		150,253	739,417	497,225
Canada	Onshore	30,695		11,527	60,598	34,910
	Offshore	31,772		11,077	49,834	35,691
Other		—		(58)	—	1,806
Total crude oil and condensate revenue		656,810		227,349	1,147,606	755,418

Net natural gas liquids revenue
United States	Onshore	9,596		3,876	17,124	9,379
	Offshore	10,766		3,464	20,820	8,490
Canada	Onshore	3,240		1,276	7,227	3,310
Total natural gas liquids revenue		23,602		8,616	45,171	21,179

Net natural gas revenue
United States	Onshore	6,872		4,090	13,315	9,648
	Offshore	17,273		10,665	39,411	25,660
Canada	Onshore	54,272		35,025	105,853	74,398
Total natural gas revenue		78,417		49,780	158,579	109,706
Total revenue from contracts with customers		758,829		285,745	1,351,356	886,303

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

Contract Balances and Asset Recognition

As of June 30, 2021, and December 31, 2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $206.6 million and $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, 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 contracts that have financing components as at June 30, 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.

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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, 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, 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 2021

Contracts to sell natural gas at USD index pricing

10 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD index pricing

8 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at CAD fixed prices

5 MMCFD

Canada

Natural Gas

Q4 2022

Contracts to sell natural gas at USD fixed pricing

20 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at USD index pricing

25 MMCFD

Canada

Natural Gas

Q4 2023

Contracts to sell natural gas at CAD fixed prices

38 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD index pricing

31 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

100 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at CAD fixed prices

34 MMCFD

Canada

Natural Gas

Q4 2024

Contracts to sell natural gas at USD fixed pricing

15 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCFD

Canada

NGL

Q3 2023

Contracts to sell natural gas liquids at various CAD pricing

952 BOED

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

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

Note D – Property, Plant, and Equipment

Exploratory Wells

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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


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

Capitalized exploratory well costs charged to expense	—		(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,
	2021				2020

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

Of the $183.6 million of exploratory well costs capitalized more than one year at June 30, 2021, $91.5 million is in Vietnam, $46.2 million is in the U.S., $25.7 million is in Brunei, $15.4 million is in Mexico, and $4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Impairments

During the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans.

In 2020, declines in future oil and natural gas prices (principally driven by reduced demand from the COVID-19 pandemic) led to impairments in certain 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 June 30,
(Thousands of dollars)	2021		2020
U.S.	$	—	947,437
Canada	171,296		—
Other Foreign	—		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 – Assets Held for Sale and Discontinued Operations

The Company has accounted for its former U.K. and 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, 2021 and 2020 were as follows:


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


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

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

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


(Thousands of dollars)	June 30, 2021		December 31, 2020
Current assets
Cash	$	—	10,185

Inventories	—		406

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

Total current assets associated with assets held for sale	$	40,820	327,736





Current liabilities
Accounts payable	$	—	5,306
Other accrued liabilities	—		45
Current maturities of long-term debt (finance lease)	—		737
Taxes payable	—		1,510

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

Note F – Financing Arrangements and Debt

As of June 30, 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, 2021, the Company had no outstanding borrowings under the RCF and $31.0 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2021, the interest rate in effect on borrowings under the facility was 1.78%. At June 30, 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.

Subsequent to quarter end, the Company issued a notice of partial redemption with respect to $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to, 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,
(Thousands of dollars)	2021		2020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹	$	(104,775)	227,710
Decrease in inventories	8,938		13,968
(Increase) in prepaid expenses	(1,945)		(20,712)
Increase (decrease) in accounts payable and accrued liabilities ¹	124,699		(219,228)
(Decrease) in income taxes payable	(352)		(403)
Net decrease in noncash operating working capital	$	26,565	1,335
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	1,474	(7)
Interest paid, net of amounts capitalized of $7.4 million in 2021 and $4.9 million in 2020	80,546		100,745

Non-cash investing activities:
Asset retirement costs capitalized ²	$	6,669	6,342
Decrease in capital expenditure accrual	20,614		58,602

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

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

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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.

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


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

	Six Months Ended June 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	2021		2020	2021	2020
Service cost	$	3,536	4,332	653	893
Interest cost	8,586		11,554	1,042	1,588
Expected return on plan assets	(12,288)		(12,641)	—	—
Amortization of prior service cost (credit)	312		366	—	—
Recognized actuarial loss	10,560		8,533	(15)	—
Net periodic benefit expense	$	10,706	12,144	1,680	2,481
Other - curtailment	—		586	—	(1,825)
Other - special termination benefits	—		8,435	—	—
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.

During the six-month period ended June 30, 2021, the Company made contributions of $19.5 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 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 Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5 million 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.

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

During the first 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 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, 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,
(Thousands of dollars)	2021		2020
Compensation charged against income before tax benefit	$	18,045	10,272
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).

Note J – Earnings 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, 2021 and 2020. The following table reports the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2021	2020	2021	2020
Basic method	154,394,602	153,580,758	154,153,158	153,428,666
Dilutive stock options and restricted stock units ¹	—	—	—	—
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, 2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

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


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

Note K – Income Taxes

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


	2021	2020
Three months ended June 30,	29.3%	22.7%
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 was higher than the 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 six-month period ended June 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to loss generated in Canada, which has a higher tax rate, as well as no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

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

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of June 30, 2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; Malaysia – 2014; and United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of 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 and amortized to the income statement over time. During the six-month period ended June 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.

Commodity Price Risks

At June 30, 2021, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing through December 2021 at an average price of $42.77, and 20,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2022 at an average price of $44.88. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.

At June 30, 2020, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of December 2020 at an average price of $56.42, and 2,000 barrels per day in WTI crude oil swap contracts maturing from January through December 2021 at an average price of $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 no foreign currency exchange short-term derivatives outstanding at June 30, 2021 and 2020.

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

June 30, 2021

December 31, 2020

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

—

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


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

Liabilities:
Nonqualified employee savings plan	$	17,188	—	—	17,188	14,988	—	—	14,988
Commodity derivative contracts	—		425,625	—	425,625	—	102,675	—	102,675
Contingent consideration	—		—	209,682	209,682	—	—	133,004	133,004
	$	17,188	425,625	209,682	652,495	14,988	102,675	133,004	250,667

The fair value of commodity (WTI crude oil) derivative contracts in 2021 and 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 two acquisitions in 2019 and 2018, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other expense (benefit) in the Consolidated Statements of Operations. Contingent consideration is payable annually in years 2022 to 2026.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at June 30, 2021 and December 31, 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, 2020 and June 30, 2021 and the changes during the six-month period ended June 30, 2021, are presented net of taxes in the following table.


(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		—		—		37,842
Reclassifications to income	—		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)		—		(553,519)

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

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

Note N – Environmental and Other Contingencies

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

ENVIRONMENTAL 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. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

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

There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

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

Note O – Business Segments

Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.


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

			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
(Millions of dollars)			External Revenues	Income (Loss)	External Revenues	Income (Loss)
Exploration and production ¹
United States			1,139.2	313.7	739.8	(839.1)
Canada			224.6	(111.6)	148.9	(26.4)
Other			—	(17.3)	1.8	(61.3)
Total exploration and production			1,363.8	184.8	890.5	(926.8)
Corporate			(434.2)	(478.8)	324.8	99.8
Continuing operations			929.6	(294.0)	1,215.3	(827.0)
Discontinued operations, net of tax			—	0.1	—	(6.1)
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 26 and 27.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases

Nature of Leases

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

Related Expenses

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


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

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

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

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

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

Maturity of Lease Liabilities


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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases (Contd.)

Lease Term and Discount Rate


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

Other Information


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

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary

In 2021, the global dissemination of several vaccinations in response to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to increased economic activity and subsequently increased demand for oil and gas. However emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the outlook for future demand for oil and gas, and hence volatility in current and future prices for Murphy’s product.

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

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

For the three months ended June 30, 2021, West Texas Intermediate (WTI) crude oil prices averaged approximately $66 per barrel (compared to $58 in the first quarter of 2021 and $28 in the second quarter of 2020). The closing price for WTI at the end of the second quarter of 2021 was approximately $71 per barrel, reflecting a 52% increase from the price at the end of 2020 and a 14% increase from the first quarter 2021 closing price. The average price in July 2021 was $72.43 per barrel. As of close on August 3, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $69.71 and $65.34 per 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 FPS. The Company reported net loss from continuing operations of $323.1 million for the second quarter of 2020. This amount included loss attributable to noncontrolling interest of $7.2 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions of $145.8 million.

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

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

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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 transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of project costs from inception to closing with proceeds of $267.7 million.

Also, 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 2022 notes were redeemed for total use of funds of $619.5 million, which includes redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and incurred closing costs of $8.0 million. The proceeds from issue are reported net of costs to issue on the balance sheet.

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)	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)

1 The Company has presented its 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)
	Three Months Ended June 30,			Six Months Ended June 30,
(Millions of dollars)	2021		2020	2021	2020
Exploration and production
United States	$	194.7	(143.1)	313.7	(839.1)
Canada	12.7		(19.5)	(111.6)	(26.4)
Other	(10.4)		(9.0)	(17.3)	(61.3)
Total	$	197.0	(171.6)	184.8	(926.8)

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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,
(Millions of dollars, except per barrel of oil equivalents sold)	2021		2020	2021	2020
Net loss attributable to Murphy (GAAP)	$	(63.1)	(317.1)	(350.5)	(733.2)
Income tax benefit	(11.2)		(94.8)	(99.3)	(186.3)
Interest expense, net	43.4		38.6	131.5	79.7
Depreciation, depletion and amortization expense ¹	217.3		219.1	405.6	505.3
EBITDA attributable to Murphy (Non-GAAP)	186.4		(154.2)	87.3	(334.5)
Mark-to-market loss (gain) on crude oil derivative contracts	130.9		184.5	284.4	(173.8)
Impairment of assets ¹	—		19.6	171.3	886.0
Mark-to-market loss (gain) on contingent consideration	61.8		15.7	76.7	(43.5)
Accretion of asset retirement obligations ¹	9.5		10.5	20.0	20.4
Unutilized rig charges	2.5		4.5	5.3	8.0
Foreign exchange losses (gains)	—		1.4	1.3	(3.3)
Discontinued operations (income) loss	0.1		1.2	(0.1)	6.1
Restructuring expenses	—		41.4	—	41.4
Inventory loss	—		—	—	4.8






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

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	$	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 exclude the portion attributable to the non-controlling interest.

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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.

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

Results of Operations (contd.)

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


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

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

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

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

Results of Operations (contd.)

Exploration and Production

Second quarter 2021 vs. 2020

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

United States E&P operations reported earnings of $194.7 million in the second quarter of 2021 compared to a loss of $143.1 million in the second quarter of 2020. Results were $337.8 million favorable in the 2021 quarter compared to the 2020 period due to higher revenues ($420.6 million), lower lease operating expenses ($26.3 million), lower impairment charge ($19.6 million), and general and administrative expenses (G&A: $2.3 million), partially offset by higher income tax expense ($87.6 million), other operating expense ($48.7 million) and depreciation, depletion and amortization ($4.2 million). Higher revenues were primarily due to higher commodity prices, higher Eagle Ford Shale volumes (due to higher capital expenditures), and higher volumes in the U.S. Gulf of Mexico (GOM), due to a 3.5% working interest acquisition in the Lucius field. Lower lease operating expense was primarily attributable to well workers in the GOM in 2020. Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices in 2020). Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher other operating expense is primarily due to unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) 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 of 2020. Results were favorable $32.2 million compared to the 2020 period primarily due to higher revenue ($61.4 million) and lower depreciation and amortization ($6.2 million), partially offset by higher tax expense ($18.2 million), higher lease operating expenses ($8.4 million), higher transportation, gathering, and processing expenses ($6.5 million), and lower other operating income ($2.1 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 Duvernay due to normal well decline. Higher lease operating and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss 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. The result was $1.4 million unfavorable in the 2021 period versus 2020 primarily due higher exploration expenses and income tax expense.

Six months 2021 vs. 2020

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

United States E&P operations reported earnings of $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. Results were $1,152.8 million favorable in the 2021 quarter compared to the 2020 period primarily due to no impairment charges in the current period (2020: $947.4 million). Further, the change year over year is driven by higher revenues ($399.4 million), lower depreciation, depletion and amortization (DD&A: $93.7 million), lower lease operating expenses (LOE: $88.4 million), lower transportation, gathering, and processing charges ($4.0 million) and lower G&A ($0.5 million), partially offset by higher income tax expense ($279.2 million) and higher other operating expense ($115.9 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of decreased oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to higher Gulf of Mexico workover costs in the prior year at Cascade ($49.3 million) and Dalmatian ($20.5 million). Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price and lower DD&A and LOE. Higher other operating expense is primarily due to 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.

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. 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 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

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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 of 2021 compared to a loss of $61.3 million in the prior year. Results were $44.0 million favorable compared to the 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 higher tax benefits ($171.9 million), lower restructuring 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 2021 primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022. Higher income tax benefits are a result of pre-tax loss driven by the higher realized and unrealized losses on forward swap commodity contracts. Lower restructuring charges and G&A expenditures are due to the 2020 cost reduction efforts which included closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

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 averaged $65.57 per barrel in the 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 U.S. NGL was $22.18 per barrel in the 2021 quarter compared to $7.67 per barrel in 2020. The average sales price for NGL in Canada was $30.63 per barrel in the 2021

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

Results of Operations (contd.)

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 averaged 369 million cubic feet per day (MMCFD) in the second quarter 2021 compared to 356 MMCFD in 2020. The increase of 13 MMCFD was a result of higher volumes in Canada (8 MMCFD), in the Gulf of Mexico (3 MMCFD) and in the Eagle Ford Shale (2 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Higher volumes in the Gulf of Mexico are principally due to higher natural gas volumes at Lucius and Neidermeyer.

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

Six months 2021 vs. 2020

Total hydrocarbon production from all E&P continuing operations averaged 173,762 barrels of oil equivalent per day in the first six months of 2021, which represented a 8% decrease from the 189,350 barrels per day produced in the first six months of 2020. The decrease in production is principally due to lower capital expenditures throughout 2020 to support generating positive free cashflow.

Average crude oil and condensate production from continuing operations was 103,434 barrels per day in the first six months of 2021 compared to 115,396 barrels per day in the first six months of 2020. The decrease of 11,962 barrels per day was principally due to lower Gulf of Mexico production (6,439 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 (these operational issues are now resolved), offset by higher second quarter production at Lucius. On a worldwide basis, the Company’s crude oil and condensate prices averaged $62.14 per barrel in the first six months of 2021 compared to $35.65 per barrel in the 2020 period, an increase of 74% year over year.

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

Natural gas sales volumes from continuing operations averaged 359 million cubic feet per day (MMCFD) in the first six months of 2021 compared to 368 MMCFD in 2020. The decrease of 9 MMCFD was the result of lower volumes in Eagle Ford (4 MMCFD), the Gulf of Mexico (3 MMCFD) and Canada (2 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). Lower volumes in Canada and Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting the Eagle Ford Shale in the first quarter of 2021.

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

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

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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, 2021 and 2020.


		Three Months Ended June 30,		Six Months Ended June 30,
Barrels per day unless otherwise noted		2021	2020	2021	2020
Continuing operations
Net crude oil and condensate
United States	Onshore	31,253	27,986	26,734	29,510
	Gulf of Mexico 1	68,468	67,002	66,427	72,866
Canada	Onshore	5,558	7,872	5,921	7,353
	Offshore	3,689	5,852	4,137	5,495
Other		359	—	215	172
Total net crude oil and condensate - continuing operations		109,327	108,712	103,434	115,396
Net natural gas liquids
United States	Onshore	5,327	5,303	4,634	5,444
	Gulf of Mexico 1	4,763	5,219	4,721	5,944
Canada	Onshore	1,162	1,018	1,197	1,209
Total net natural gas liquids - continuing operations		11,252	11,540	10,552	12,597
Net natural gas – thousands of cubic feet per day
United States	Onshore	29,653	27,697	25,855	29,830
	Gulf of Mexico 1	71,962	68,717	72,308	75,333
Canada	Onshore	267,210	259,108	260,491	262,978
Total net natural gas - continuing operations		368,825	355,522	358,654	368,141
Total net hydrocarbons - continuing operations including NCI 2,3		182,050	179,506	173,762	189,350
Noncontrolling interest
Net crude oil and condensate – barrels per day		(9,800)	(10,719)	(9,489)	(11,370)
Net natural gas liquids – barrels per day		(370)	(443)	(362)	(501)
Net natural gas – thousands of cubic feet per day		(4,024)	(4,059)	(4,091)	(4,575)
Total noncontrolling interest		(10,841)	(11,839)	(10,533)	(12,634)
Total net hydrocarbons - continuing operations excluding NCI 2,3		171,209	167,667	163,229	176,716

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

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

3 NCI – noncontrolling interest in MP GOM.

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

Results of Operations (contd.)

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


		Three Months Ended June 30,		Six Months Ended June 30,
		2021	2020	2021	2020
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States	Onshore	64.55	21.42	61.60	34.59
	Gulf of Mexico 1	65.95	24.77	62.56	37.00
Canada 2	Onshore	60.69	16.09	56.55	26.09
	Offshore	73.20	20.48	67.51	35.28
Other		—	—	—	63.51
Natural gas liquids – dollars per barrel
United States	Onshore	19.75	8.03	20.38	9.45
	Gulf of Mexico 1	24.84	7.29	24.36	7.85
Canada 2	Onshore	30.63	13.78	33.34	15.04
Natural gas – dollars per thousand cubic feet
United States	Onshore	2.54	1.62	2.84	1.74
	Gulf of Mexico 1	2.64	1.71	3.01	1.87
Canada 2	Onshore	2.23	1.49	2.25	1.55

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

2 U.S. dollar equivalent.

Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $686.3 million for the first six months of 2021 compared to $369.4 million during the same period in 2020. The increased cash from operating activities is primarily attributable to higher revenue from sales to customers ($465.1 million), lower lease operating expense ($80.2 million), lower working capital ($25.2 million), and lower general and administrative expense ($17.3 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $156.3 million; 2020: realized gain of $150.9 million).

Cash Required by Investing Activities

Net cash required by investing activities was $193.7 million for the first six months of 2021 compared to $589.2 million during the same period in 2020. Property additions and dry hole costs, which includes amounts expensed, were $463.0 million and $589.2 million in the first six months of 2021 and 2020, respectively. 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 reimburses the Company for previously incurred capital expenditures. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay.

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

Financial Condition (contd.)

Total accrual basis capital expenditures were as follows:


	Six Months Ended June 30,
(Millions of dollars)	2021		2020
Capital Expenditures
Exploration and production	$	449.4	550.2
Corporate	8.8		7.4
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,
(Millions of dollars)	2021		2020
Property additions and dry hole costs per cash flow statements	$	445.3	537.6
Property additions King's Quay per cash flow statements	17.7		51.6

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

Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of capital expenditure reductions to support generating positive free cash flow.

Cash Used in/ Provided by Financing Activities

Net cash required by financing activities was $386.7 million for the first six months of 2021 compared to net cash provided by financing activities of $60.0 million during the same period in 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 revolving credit facility ($370.0 million), offset by repayments on the revolving credit facility ($200.0 million), cash dividends to shareholders ($57.6 million), and distributions to the NCI ($32.4 million).

Working Capital

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

Capital Employed

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

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

Financial Condition (contd.)

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


	June 30, 2021				December 31, 2020
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	2,762.9	41.6	%	$	2,988.1	41.5	%
Murphy shareholders' equity	3,880.6		58.4	%	4,214.3		58.5	%
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, 2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $121.9 million in Canada and $8.4 million in Brunei. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

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

Outlook

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

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 be routinely reviewed during 2021 and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2021 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt. In the third quarter of 2021, the Company announced the redemption of $150.0 million in aggregate principal amount of its 6.875% notes due 2024.

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the progress and acceptance of the vaccinations which has positively impacted current and expected future energy demand for the next year compared to one year ago.

As of August 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

Area

Start Date

End Date

United States

WTI ¹

Fixed price derivative swap

45,000

$42.77

7/1/2021

12/31/2021

United States

WTI ¹

Fixed price derivative swap

20,000

$44.88

1/1/2022

12/31/2022

1 West Texas Intermediate

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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$2.57

7/1/2021

12/31/2021

Montney

Natural Gas

Fixed price forward sales at AECO

231

C$2.42

1/1/2022

1/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

221

C$2.41

2/1/2022

4/30/2022

Montney

Natural Gas

Fixed price forward sales at AECO

250

C$2.40

5/1/2022

5/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

292

C$2.39

6/1/2022

10/31/2022

Montney

Natural Gas

Fixed price forward sales at AECO

311

C$2.40

11/1/2022

12/31/2022

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

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2020 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 37 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

There were no derivative foreign exchange contracts in place at June 30, 2021.

ITEM 4. CONTROLS AND PROCEDURES

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

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

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

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2020 Form 10-K filed on February 26, 2021. The Company has not identified any additional risk factors not previously disclosed in its 2020 Form 10-K report.

ITEM 6. EXHIBITS

The Exhibit Index on page 39 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 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

10.26	Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors	Exhibit A to definitive proxy statement filed March 26, 2021
*10.27	Form of non-employee director restricted stock unit award – stock settled grant agreement (2021 NED Plan)
*31.1	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS	XBRL Instance Document
101. SCH	XBRL Taxonomy Extension Schema Document
101. CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	XBRL Taxonomy Extension Labels Linkbase Document
101. PRE	XBRL Taxonomy Extension Presentation Linkbase