Annual Statements Open main menu

MURPHY OIL CORP - Quarter Report: 2021 March (Form 10-Q)


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 March 31, 2021
OR
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
mur-20210331_g1.jpg
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware71-0361522
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-20077024
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 classTrading SymbolName of each exchange on which registered
Common Stock, $1.00 Par ValueMURNew 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 April 30, 2021 was 154,399,812.



MURPHY OIL CORPORATION
TABLE OF CONTENTS
Page
1

Table of Contents
PART I – FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)
March 31,
2021
December 31,
2020
ASSETS
Current assets
Cash and cash equivalents$230,870 310,606 
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020
278,819 262,014 
Inventories66,585 66,076 
Prepaid expenses37,634 33,860 
Assets held for sale77,397 327,736 
Total current assets691,305 1,000,292 
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,869,715 in 2021 and $11,455,305 in 2020
8,216,722 8,269,038 
Operating lease assets911,941 927,658 
Deferred income taxes433,617 395,253 
Deferred charges and other assets30,759 28,611 
Total assets$10,284,344 10,620,852 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable$538,327 407,097 
Income taxes payable17,370 18,018 
Other taxes payable18,032 22,498 
Operating lease liabilities102,983 103,758 
Other accrued liabilities174,575 150,578 
Liabilities associated with assets held for sale14,097 14,372 
Total current liabilities865,384 716,321 
Long-term debt2,755,596 2,988,067 
Asset retirement obligations904,085 816,308 
Deferred credits and other liabilities691,254 680,580 
Non-current operating lease liabilities829,760 845,088 
Deferred income taxes138,656 180,341 
Total liabilities6,184,735 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 value914,303 941,692 
Retained earnings5,062,813 5,369,538 
Accumulated other comprehensive loss(575,610)(601,333)
Treasury stock(1,661,416)(1,690,661)
Murphy Shareholders' Equity3,935,191 4,214,337 
Noncontrolling interest164,418 179,810 
Total equity4,099,609 4,394,147 
Total liabilities and equity$10,284,344 10,620,852 
See Notes to Consolidated Financial Statements, page 7.
2

Table of Contents
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
Three Months Ended
March 31,
(Thousands of dollars, except per share amounts)
20212020
Revenues and other income
Revenue from sales to customers$592,527 600,558 
(Loss) gain on crude contracts(214,385)400,672 
Gain on sale of assets and other income1,843 2,498 
Total revenues and other income379,985 1,003,728 
Costs and expenses
Lease operating expenses147,164 209,148 
Severance and ad valorem taxes9,231 9,422 
Transportation, gathering and processing 42,912 44,367 
Exploration expenses, including undeveloped lease amortization11,780 20,126 
Selling and general expenses29,503 36,772 
Depreciation, depletion and amortization198,278 306,102 
Accretion of asset retirement obligations10,492 9,966 
Impairment of assets171,296 967,530 
Other expense (benefit)21,079 (45,188)
Total costs and expenses641,735 1,558,245 
Operating loss from continuing operations(261,750)(554,517)
Other income (loss)
Interest and other income (loss)(5,341)241 
Interest expense, net(88,100)(41,097)
Total other loss(93,441)(40,856)
Loss from continuing operations before income taxes(355,191)(595,373)
Income tax benefit(88,159)(91,533)
Loss from continuing operations(267,032)(503,840)
Income (loss) from discontinued operations, net of income taxes208 (4,862)
Net loss including noncontrolling interest(266,824)(508,702)
Less: Net income (loss) attributable to noncontrolling interest20,614 (92,598)
NET LOSS ATTRIBUTABLE TO MURPHY$(287,438)(416,104)
LOSS PER COMMON SHARE – BASIC
Continuing operations$(1.87)(2.68)
Discontinued operations (0.03)
Net loss$(1.87)(2.71)
LOSS PER COMMON SHARE – DILUTED
Continuing operations$(1.87)(2.68)
Discontinued operations (0.03)
Net loss$(1.87)(2.71)
Cash dividends per Common share0.125 0.25 
Average Common shares outstanding (thousands)
Basic153,953 153,313 
Diluted153,953 153,313 
See Notes to Consolidated Financial Statements, page 7.
3

Table of Contents
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)


Three Months Ended
March 31,
(Thousands of dollars)20212020
Net (loss) income including noncontrolling interest$(266,824)(508,702)
Other comprehensive (loss) income, net of tax
Net (loss) gain from foreign currency translation19,897 (118,411)
Retirement and postretirement benefit plans4,136 (9,711)
Deferred loss on interest rate hedges reclassified to interest expense1,690 299 
Other comprehensive (loss) income 25,723 (127,823)
COMPREHENSIVE (LOSS) INCOME$(241,101)(636,525)
See Notes to Consolidated Financial Statements, page 7.
4

Table of Contents
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
Three Months Ended
March 31,
(Thousands of dollars)20212020
Operating Activities
Net loss including noncontrolling interest$(266,824)(508,702)
Adjustments to reconcile net loss to net cash provided by continuing operations activities
(Income) loss from discontinued operations(208)4,862 
Depreciation, depletion and amortization198,278 306,102 
Previously suspended exploration costs 717 97 
Amortization of undeveloped leases4,602 7,478 
Accretion of asset retirement obligations10,492 9,966 
Impairment of assets171,296 967,530 
Deferred income tax benefit(88,867)(81,373)
Mark to market loss (gain) on contingent consideration14,923 (59,151)
Mark to market loss (gain) on crude contracts153,505 (358,302)
Long-term non-cash compensation12,124 9,805 
Net (increase) decrease in noncash working capital(9,052)107,827 
Other operating activities, net36,780 (13,482)
Net cash provided by continuing operations activities237,766 392,657 
Investing Activities
Property additions and dry hole costs(240,545)(354,834)
Property additions for King's Quay FPS(17,734)(21,296)
Proceeds from sales of property, plant and equipment268,023 — 
Net cash provided (required) by investing activities9,744 (376,130)
Financing Activities
Borrowings on revolving credit facility 140,000 170,000 
Repayment of revolving credit facility (340,000)— 
Retirement of debt(576,358)(3,570)
Debt issuance, net of cost541,980 (613)
Early redemption of debt cost(34,177)— 
Distributions to noncontrolling interest(36,006)(32,399)
Cash dividends paid(19,287)(38,392)
Withholding tax on stock-based incentive awards(3,794)(7,094)
Capital lease obligation payments(178)(168)
Net cash (required) provided by financing activities(327,820)87,764 
Cash Flows from Discontinued Operations 1
Operating activities (1,202)
Investing activities 4,494 
Net cash provided by discontinued operations 3,292 
Effect of exchange rate changes on cash and cash equivalents574 (3,298)
Net (decrease) increase in cash and cash equivalents(79,736)100,993 
Cash and cash equivalents at beginning of period310,606 306,760 
Cash and cash equivalents at end of period$230,870 407,753 
1  Net cash provided by discontinued operations is not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 7.
5

Table of Contents
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

Three Months Ended
March 31,
(Thousands of dollars)
20212020
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 March 31, 2021 and 195,083,364 shares at March 31, 2020
Balance at beginning of period195,101 195,089 
Exercise of stock options 12 
Balance at end of period195,101 195,101 
Capital in Excess of Par Value
Balance at beginning of period941,692 949,445 
Exercise of stock options, including income tax benefits(39)(156)
Restricted stock transactions and other(33,000)(32,604)
Share-based compensation5,650 8,245 
Balance at end of period914,303 924,930 
Retained Earnings
Balance at beginning of period5,369,538 6,614,304 
Net (loss) income for the period(287,438)(416,104)
Cash dividends(19,287)(38,392)
Balance at end of period5,062,813 6,159,808 
Accumulated Other Comprehensive Loss
Balance at beginning of period(601,333)(574,161)
Foreign currency translation (loss) gain, net of income taxes19,897 (118,411)
Retirement and postretirement benefit plans, net of income taxes4,136 (9,711)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes1,690 299 
Balance at end of period(575,610)(701,984)
Treasury Stock
Balance at beginning of period(1,690,661)(1,717,217)
Awarded restricted stock, net of forfeitures29,206 25,511 
Exercise of stock options39 — 
Balance at end of period – 40,784,118 shares of Common Stock in 2021 and 21,456,366 shares of Common Stock in 2020, at cost
(1,661,416)(1,691,706)
Murphy Shareholders’ Equity3,935,191 4,886,149 
Noncontrolling Interest
Balance at beginning of period179,810 337,151 
Net (loss) income attributable to noncontrolling interest20,614 (92,598)
Distributions to noncontrolling interest owners(36,006)(32,399)
Balance at end of period164,418 212,154 
Total Equity$4,099,609 5,098,303 
See Notes to Consolidated Financial Statements, page 7.
6

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas exploration and production company that conducts its business through various operating subsidiaries.  The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.
In connection with the LLOG acquisition, 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 March 31, 2021, our maximum exposure to loss was $3.5 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2021 and December 31, 2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 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.
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 period ended March 31, 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.
7

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into 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 gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.
U.S. - In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.  Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada - In Canada, contracts 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.
8

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-month period ended March 31, 2021 and 2020, the Company recognized $592.5 million and $600.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
Three Months Ended
March 31,
(Thousands of dollars)20212020
Net crude oil and condensate revenue
United States
Onshore$114,490 131,236 
                     Offshore328,341 346,972 
Canada    
Onshore29,903 23,383 
Offshore18,062 24,614 
Other
 1,864 
Total crude oil and condensate revenue
490,796 528,069 
Net natural gas liquids revenue
United States
Onshore7,528 5,503 
 
Offshore10,054 5,026 
Canada
Onshore3,987 2,034 
Total natural gas liquids revenue
21,569 12,563 
Net natural gas revenue
United States
Onshore6,443 5,558 
Offshore22,138 14,995 
Canada   
Onshore51,581 39,373 
Total natural gas revenue
80,162 59,926 
Total revenue from contracts with customers592,527 600,558 
(Loss) gain on crude contracts(214,385)400,672 
Gain on sale of assets and other income1,843 2,498 
Total revenue and other income$379,985 1,003,728 
Contract Balances and Asset Recognition
As of March 31, 2021, and December 31, 2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $179.1 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 upstream oil and gas sale contracts that have financing components as at March 31, 2021.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
9

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Performance Obligations
The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer.  Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.
As of March 31, 2021, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:
Current Long-Term Contracts Outstanding at March 31, 2021
Approximate Volumes
LocationCommodityEnd DateDescription
U.S.OilQ4 2021Fixed quantity delivery in Eagle Ford17,000 BOED
U.S.Natural Gas and NGLQ1 2023Deliveries from dedicated acreage in Eagle FordAs produced
CanadaNatural GasQ4 2021Contracts to sell natural gas at USD Index pricing10 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at USD Index pricing8 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at Alberta AECO fixed prices5 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at USD index fixed pricing20 MMCFD
CanadaNatural GasQ4 2023Contracts to sell natural gas at USD Index pricing25 MMCFD
CanadaNatural GasQ4 2023Contracts to sell natural gas at Alberta AECO fixed prices38 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD Index pricing31 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at Alberta AECO fixed prices134 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD index fixed pricing15 MMCFD
CanadaNatural GasQ4 2026Contracts to sell natural gas at USD Index pricing49 MMCFD
CanadaNGLQ3 2023Contracts to sell natural gas liquids at various CAD pricing730 BOED
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant, and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of March 31, 2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $182.4 million.  The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2021 and 2020.
(Thousands of dollars)20212020
Beginning balance at January 1$181,616 217,326 
Additions pending the determination of proved reserves785 816 
Capitalized exploratory well costs charged to expense (39,709)
Balance at March 31$182,401 178,433 
10

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)

The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below).
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.  The projects are aged based on the last well drilled in the project.
March 31,
20212020
(Thousands of dollars)AmountNo. of WellsNo. of ProjectsAmountNo. of WellsNo. of Projects
Aging of capitalized well costs:
Zero to one year$   24,637 
One to two years23,514 3 3 31,541 
Two to three years30,562 2 2 — — — 
Three years or more128,325 6  122,255 — 
$182,401 11 5 178,433 11 
Of the $182.4 million of exploratory well costs capitalized more than one year at March 31, 2021, $90.6 million is in Vietnam, $45.9 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 current status, including agreements with the partners, of operating and production plans.
In the first quarter of 2020, declines in future oil and natural gas prices (principally driven by increased supply from foreign oil producers and reduced demand in response to the COVID-19 pandemic) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $967.5 million to reduce the carrying values to their estimated fair values as of March 31, 2020 at select properties.
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The following table reflects the recognized impairments for the three months ended March 31, 2021 and 2020.
Three Months Ended
March 31,
(Thousands of dollars)20212020
U.S.$ 927,821 
Canada171,296  
Other Foreign 39,709 
$171,296 967,530 
Divestments
On March 17, 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company for previously incurred capital expenditures.

Note E – Assets Held for Sale and Discontinued Operations
The Company has accounted for its former Malaysian exploration and production operations and its former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month periods ended March 31, 2021 and 2020 were as follows:
11

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)


Three Months Ended
March 31,
(Thousands of dollars)20212020
Revenues $44 4,073 
Costs and expenses
Other costs and expenses (benefits)(164)8,935 
(Loss) income before taxes208 (4,862)
Income tax expense — 
(Loss) income from discontinued operations$208 (4,862)
The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production operations and the Company’s office building in El Dorado, Arkansas that are reflected as held for sale on the Company’s Consolidated Balance Sheets.
(Thousands of dollars)March 31,
2021
December 31,
2020
Current assets
Cash$9,469 10,185 
Inventories193 406 
Property, plant, and equipment, net58,294 307,704 
Deferred income taxes and other assets9,441 9,441 
Total current assets associated with assets held for sale$77,397 327,736 
Current liabilities
Accounts payable$5,213 5,306 
Other accrued liabilities36 45 
Current maturities of long-term debt (finance lease)746 737 
Taxes payable1,510 1,510 
Long-term debt (finance lease)6,325 6,513 
Asset retirement obligation267 261 
Total current liabilities associated with assets held for sale$14,097 14,372 

Note F – Financing Arrangements and Debt
As of March 31, 2021, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At March 31, 2021, the Company had no outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At March 31, 2021, the interest rate in effect on borrowings under the facility was 1.78%. At March 31, 2021, the Company was in compliance with all covenants related to the RCF.

In March 2021, the Company issued $550 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.0 million on the issuance of these new notes. The Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022) (collectively the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months ended March 31, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the three months ended March 31, 2021.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2021.
12

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
Three Months Ended
March 31,
(Thousands of dollars)20212020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹$(16,954)186,436 
Decrease in inventories392 7,553 
(Increase) in prepaid expenses(3,652)(10,179)
Increase (decrease) in accounts payable and accrued liabilities ¹11,810 (76,287)
Increase (decrease) in income taxes payable(648)304 
Net (increase) decrease in noncash operating working capital$(9,052)107,827 
Supplementary disclosures:
Cash income taxes paid, net of refunds$720 72 
Interest paid, net of amounts capitalized of $3.3 million in 2021 and $2.4 million in 2020
44,577 42,344 
Non-cash investing activities:
Asset retirement costs capitalized ²$6,390 280 
Decrease in capital expenditure accrual13,617 10,633 
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 in 2021.


13

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan.  All U.S. tax qualified plans meet the funding requirements of federal laws and regulations.  Contributions to foreign plans are based on local laws and tax regulations.  The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees.  The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2021 and 2020.
Three Months Ended March 31,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2021202020212020
Service cost$1,768 2,166 326 447 
Interest cost4,286 5,791 521 794 
Expected return on plan assets(6,133)(6,344) — 
Amortization of prior service cost (credit)156 183  — 
Recognized actuarial loss5,279 4,269 (7)— 
Net periodic benefit expense$5,356 6,065 840 1,241 
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 three-month period ended March 31, 2021, the Company made contributions of $10.6 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 $31.3 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 other employees.  Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. 
In May 2020, the Company’s shareholders approved the replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.
The 2020 Long-Term Plan and the 2018 Long-Term Incentive Plan authorizes the Committee to make grants of the Company’s Common Stock to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2020 Long-Term Plan expires in 2030.  A total of 5 million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.
The Stock Plan for Non-Employee Directors (2018 NED Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
During the first three months of 2021, the Committee granted 1,156,800 performance-based RSUs and 385,600 time-based RSUs to certain employees under the 2020 Long-Term Plan.  The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $16.03 per unit.  The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $12.30 per unit.  Additionally, in February 2021, the Committee granted 1,022,700 cash-settled RSUs (CRSU) to certain employees.  The CRSUs are to be settled in cash, net of applicable income
14

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

taxes, and are accounted for as liability-type awards.  The initial fair value of the CRSUs granted in February 2021 was $12.30.  Also, in February, the Committee granted 182,652 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee Directors.  These units are scheduled to vest on the first anniversary of the date of grant. The estimated fair value of these awards was $13.14 per unit on date of grant.
All stock option exercises are non-cash transactions for the Company.  The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the three-month period ended March 31, 2021.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
Three Months Ended
March 31,
(Thousands of dollars)20212020
Compensation charged against income before tax benefit$8,196 553 
Related income tax (expense) benefit recognized in income1,165 (592)
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
15

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 periods ended March 31, 2021 and 2020.  The following table reports the weighted-average shares outstanding used for these computations.
Three Months Ended
March 31,
(Weighted-average shares)20212020
Basic method153,952,552 153,312,647 
Dilutive stock options and restricted stock units ¹ — 
Diluted method153,952,552 153,312,647 
1 Due to a net loss recognized by the Company for the three-month periods ended March 31, 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
March 31,
20212020
Antidilutive stock options excluded from diluted shares1,771,575 2,490,542 
Weighted average price of these options$35.62 $42.58 

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes.  For the three-month periods ended March 31, 2021 and 2020, the Company’s effective income tax rates were as follows:
20212020
Three months ended March 31,24.8%15.4%
The effective tax rate for the three-month period ended March 31, 2021 was above the U.S. statutory tax rate of 21% primarily due to losses recorded in Canada which has a higher tax rate, exploration expenses in certain foreign jurisdictions in which no income tax benefit is currently available, as well as no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the three-month period ended March 31, 2020 was below the statutory tax rate of 21% due to impairment charges, exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM.
The 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 March 31, 2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; Malaysia – 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
16

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss and amortized to the income statement over time. During the three-month period ended March 31, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.
Commodity Price Risks
At March 31, 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 March 31, 2020, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of April 2020 at an average price of $56.42, 65,000 barrels per day in WTI crude oil swap contracts maturing in May and June 2020 at an average price of $47.20, and 45,000 barrels per day in WTI crude oil swap contracts maturing through the end of 2020 at an average price of $56.42.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at March 31, 2021 and 2020.
At March 31, 2021 and December 31, 2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
March 31, 2021December 31, 2020
(Thousands of dollars)Asset (Liability) DerivativesAsset (Liability) Derivatives
Type of Derivative ContractBalance Sheet LocationFair ValueBalance Sheet LocationFair Value
CommodityAccounts payable$ Accounts receivable$13,050 
Accounts payable(234,473)Accounts payable(89,842)
Deferred credits and other liabilities(49,034)Deferred credits and other liabilities(12,833)
For the three-month periods ended March 31, 2021 and 2020, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
Gain (Loss)
(Thousands of dollars)Statement of Operations LocationThree months ended March 31,
Type of Derivative Contract20212020
Commodity(Loss) gain on crude contracts$(214,385)400,672 
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During the three-month period ended March 31, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.
17

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2021 and December 31, 2020, are presented in the following table.
March 31, 2021December 31, 2020
(Thousands of dollars)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:
Commodity derivative contracts$    — 13,050 — 13,050 
$    — 13,050 — 13,050 
Liabilities:
Nonqualified employee savings plans$15,654   15,654 14,988 — — 14,988 
Commodity derivative contracts 283,507  283,507 — 102,675 — 102,675 
Contingent consideration  147,927 147,927 — — 133,004 133,004 
$15,654 283,507 147,927 431,434 14,988 102,675 133,004 250,667 
The fair value of WTI crude oil derivative contracts in 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. Any remaining contingent consideration payable will be due annually in years 2021 to 2026.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at March 31, 2021 and December 31, 2020.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2020 and March 31, 2021 and the changes during the three-month period ended March 31, 2021, are presented net of taxes in the following table.
18

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

(Thousands of dollars)Foreign
Currency
Translation
Gains (Losses)
Retirement
and
Postretirement
Benefit Plan
Adjustments
Deferred
Loss on
Interest Rate
Derivative
Hedges
Total
Balance at December 31, 2020$(324,011)(275,632)(1,690)(601,333)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings19,897 — — 19,897 
Reclassifications to income— 4,136 ¹1,690 ²5,826 
Net other comprehensive income (loss)19,897 4,136 1,690 25,723 
Balance at March 31, 2021$(304,114)(271,496)— (575,610)

Reclassifications before taxes of $5,252 are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2021.  See Note H for additional information.  Related income taxes of $1,116 are included in Income tax expense (benefit) for the three-month period ended March 31, 2021.
Reclassifications before taxes of $2,140 are included in Interest expense, net, for the three-month period ended March 31, 2021.  Related income taxes of $450 are included in Income tax expense (benefit) for the three-month period ended March 31, 2021.  See Note L for additional information.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to:  tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing 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 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.
19

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)

There is the possibility that environmental expenditures could be required at currently unidentified sites, and 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.
20

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 March 31, 2021Three Months Ended March 31, 2021Three Months Ended March 31, 2020
(Millions of dollars)External
Revenues
Income
(Loss)
External
Revenues
Income
(Loss)
Exploration and production ¹
United States$6,737.8 490.3 119.0 511.5 (696.0)
Canada2,364.0 104.0 (124.3)89.7 (6.9)
Other264.3  (6.9)1.8 (52.3)
Total exploration and production9,366.1 594.3 (12.2)603.0 (755.2)
Corporate917.4 (214.3)(254.8)400.7 251.4 
Assets/revenue/income (loss) from continuing operations10,283.5 380.0 (267.0)1,003.7 (503.8)
Discontinued operations, net of tax0.8  0.2 — (4.9)
Total$10,284.3 380.0 (266.8)1,003.7 (508.7)
1 Additional details about results of oil and gas operations are presented in the table on pages 25.
21

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In 2021, the effects of the ongoing coronavirus disease 2019 (COVID-19) pandemic have been tempered by the global dissemination of several vaccinations. This has led to a current and expected future recovery of energy demand. The OPEC+ group of oil producing countries scaled back production cuts marginally by 0.5 MMBOD to 7.2 MMBOD in January 2021 and 7.1 MMBOD for February and March. Outside of the OPEC+ agreement, Saudi Arabia unilaterally implemented an additional 1.0 MMBOD cut in February and March 2021. These items combined have supported a higher oil price for the Company’s product sales compared to one year ago.
For the three months ended March 31, 2021, West Texas Intermediate (WTI) crude oil prices averaged approximately $58 per barrel (compared to $46 in the first quarter of 2020 and $39 for 2020 full year). The closing price for WTI at the end of the first quarter of 2021 was approximately $62 per barrel, reflecting a 32% increase from the price at the end of 2020. The average price in April 2021 was $61.70 per barrel. As of close on May 4, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $64.70 and $60.46 per barrel, respectively.
For the three months ended March 31, 2021, the Company produced 165 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.  The Company invested $251.1 million in capital expenditures (on a value of work done basis) in the three months ended March 31, 2021, which included $17.2 million to fund the development of the King’s Quay FPS (subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of $267.0 million (which includes post tax impairment charges of $128.0 million and loss attributable to noncontrolling interest of $20.6 million) for the three months ended March 31, 2021.
For the three months ended March 31, 2020, the Company produced 199 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $378.0 million in capital expenditures (on a value of work done basis) for the three months ended March 31, 2020, which included $28.8 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $503.8 million (which includes loss attributable to noncontrolling interest of $92.6 million) for the three months ended March 31, 2020.
During the three-month periods ended March 31, 2021, crude oil and condensate volumes from continuing operations were lower than the prior year period. The decrease in production volumes is due to lower capital expenditures throughout 2020 and the first quarter of 2021 to support generating positive free cash flow. Revenue from sales to customers was 1% lower compared to 2020, whilst revenue from commodity price hedges decreased 154%, primarily as a result of increasing oil prices.
In March 2021, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the King’s Quay floating production system (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. Further, in March 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).
22

Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Results of Operations
Murphy’s income (loss) by type of business is presented below.
Income (Loss)
Three Months Ended March 31,
(Millions of dollars)20212020
Exploration and production(12.2)(755.2)
Corporate and other(254.8)251.4 
(Loss) income from continuing operations(267.0)(503.8)
Discontinued operations ¹0.2 (4.9)
Net (loss) income including noncontrolling interest(266.8)(508.7)
1 The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
Income (Loss)
Three Months Ended March 31,
(Millions of dollars)20212020
Exploration and production
United States119.0 (696.0)
Canada(124.3)(6.9)
Other (6.9)(52.3)
Total(12.2)(755.2)

























23

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net (loss) income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.
Three Months Ended
March 31,
(Millions of dollars, except per barrel of oil equivalents sold)
20212020
Net loss attributable to Murphy (GAAP)(287.4)(416.1)
Income tax benefit(88.2)(91.5)
Interest expense, net88.1 41.1 
Depreciation, depletion and amortization expense ¹188.3 286.2 
EBITDA attributable to Murphy (Non-GAAP)(99.2)(180.3)
Impairment of assets ¹171.3 866.4 
Mark-to-market loss (gain) on crude oil derivative contracts153.5 (358.3)
Mark-to-market loss (gain) on contingent consideration14.9 (59.2)
Accretion of asset retirement obligations10.5 10.0 
Unutilized rig charges2.8 3.5 
Foreign exchange losses (gains)1.3 (4.7)
Discontinued operations (income) loss(0.2)4.9 
Inventory loss 4.8 
Adjusted EBITDA attributable to Murphy (Non-GAAP)254.9 287.1 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)13,670 17,071 
Adjusted EBITDA per barrel of oil equivalents sold18.65 16.82 
1 Depreciation, depletion, and amortization expense used in the computation of EBITDA and impairment of assets used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.

24

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED MARCH 31, 2021 AND 2020
(Millions of dollars)
United
States
1
CanadaOtherTotal
Three Months Ended March 31, 2021
Oil and gas sales and other operating revenues$490.3 104.0  594.3 
Lease operating expenses116.1 30.8 0.3 147.2 
Severance and ad valorem taxes8.9 0.3  9.2 
Transportation, gathering and processing28.5 14.4  42.9 
Depreciation, depletion and amortization149.6 44.8 0.5 194.9 
Impairment of assets 171.3  171.3 
Accretion of asset retirement obligations9.0 1.5  10.5 
Exploration expenses
Dry holes and previously suspended exploration costs0.7   0.7 
Geological and geophysical0.6  0.2 0.8 
Other exploration0.6  5.0 5.6 
1.9  5.2 7.1 
Undeveloped lease amortization2.3 0.1 2.2 4.6 
Total exploration expenses4.2 0.1 7.4 11.7 
Selling and general expenses5.5 4.1 1.4 11.0 
Other21.5 3.1 (3.5)21.1 
Results of operations before taxes147.0 (166.4)(6.1)(25.5)
Income tax provisions (benefits)28.0 (42.1)0.8 (13.3)
Results of operations (excluding Corporate segment)$119.0 (124.3)(6.9)(12.2)
Three months ended March 31, 2020
Oil and gas sales and other operating revenues$511.5 89.7 1.8 603.0 
Lease operating expenses178.2 30.6 0.3 209.1 
Severance and ad valorem taxes9.1 0.3 — 9.4 
Transportation, gathering and processing34.6 9.8 — 44.4 
Depreciation, depletion and amortization247.5 52.0 0.5 300.0 
Impairment of assets927.8 — 39.7 967.5 
Accretion of asset retirement obligations8.6 1.4 — 10.0 
Exploration expenses
Dry holes and previously suspended exploration costs0.1 — — 0.1 
Geological and geophysical1.3 — 3.7 5.0 
Other exploration0.8 0.2 6.5 7.5 
2.2 0.2 10.2 12.6 
Undeveloped lease amortization5.1 0.2 2.2 7.5 
Total exploration expenses7.3 0.4 12.4 20.1 
Selling and general expenses3.7 4.4 1.6 9.7 
Other(45.7)0.2 (1.2)(46.7)
Results of operations before taxes(859.6)(9.4)(51.5)(920.5)
Income tax provisions (benefits)(163.6)(2.5)0.8 (165.3)
Results of operations (excluding Corporate segment)$(696.0)(6.9)(52.3)(755.2)
1 Includes results attributable to a noncontrolling interest in MP GOM.
25

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Exploration and Production
First quarter 2021 vs. 2020
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $119.0 million in the first three months of 2021 compared to a loss of $696.0 million in the first three months of 2020.  Results were $815 million favorable in the 2021 quarter compared to the 2020 period primarily due to no impairment charge (for the United States) in the current period (2020: $927.8 million). Further, the change year over year is driven by lower depreciation, depletion and amortization (DD&A: $97.9 million), lower lease operating expenses (LOE: $62.1 million) and lower transportation, gathering, and processing charges ($6.1 million), partially offset by higher income tax expense ($191.6 million), higher other operating expense ($67.2 million), lower revenues ($21.2 million), and higher G&A ($1.8 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of decreased oil demand and abundant oil supply at the time of the assessment. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower revenues were primarily due to lower sales volumes in the U.S., following temporary operational issues at the Cascade & Chinook and Kodiak fields in the Gulf of Mexico (these operational issues are now resolved) and lower Eagle Ford Shale volumes following lower capital expenditures throughout 2020 and the effects of a winter storm. Lower lease operating expenses were primarily due to higher Gulf of Mexico workover costs in the prior year at the Cascade asset. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price and lower DD&A and LOE. Higher other operating expense is primarily due to a unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($14.9 million).
Canadian E&P operations reported a loss of $124.3 million in the first three months of 2021 compared to a loss of $6.9 million in the first three months quarter of 2020.  Results were $117.4 million unfavorable compared to the 2020 period primarily due to an impairment charge ($171.3 million) in the current period, partially offset by higher income tax benefit ($39.6 million), higher revenue ($14.3 million) and lower DD&A ($7.2 million). The impairment charge in the current year is due to the current status, including agreements with the partners, of operating and production plans at Terra Nova. The operator and joint venture partners continue to evaluate options that could support a long-term production plan for Terra Nova. Higher income tax benefit is a result of a pre-tax loss driven by the impairment charge. Higher revenues were primarily attributable to higher prices (oil and condensate, natural gas and NGLs) versus the prior year. Lower lease operating expenses and lower DD&A were a result of lower sales volume following reduced capital expenditures throughout 2020.
Other international E&P operations reported a loss from continuing operations of $6.9 million in the first three months of 2021 compared to a loss of $52.3 million in the prior year.  The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.

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

26

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Production Volumes and Prices
First quarter 2021 vs. 2020
Total hydrocarbon production from continuing operations averaged 165,382 barrels of oil equivalent per day in the first quarter of 2021, which represented a 17% decrease from the 199,194 barrels per day produced in first quarter 2020. The decrease in production volumes is principally due to lower capital expenditures throughout 2020 and the first quarter of 2021 to support generating positive free cashflow.
Average crude oil and condensate production from continuing operations was 97,475 barrels per day in the first quarter of 2021 compared to 122,078 barrels per day in the first quarter of 2020. The decrease of 24,603 barrels per day was associated with lower Eagle Ford Shale production (8,868 barrels per day) due to lower capital expenditures and a winter storm resulting in shut-in production (2,250 barrels per day). Lower volumes in the Gulf of Mexico (14,367 barrels per day) are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). On a worldwide basis, the Company’s crude oil and condensate prices averaged $58.08 per barrel in the first quarter 2021 compared to $46.66 per barrel in the 2020 period, an increase of 24% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 9,845 barrels per day in the first quarter 2021 compared to 13,656 barrels per day in the 2020 period. The average sales price for U.S. NGL was $22.68 per barrel in the 2021 quarter compared to $9.44 per barrel in 2020. The average sales price for NGL in Canada was $35.92 per barrel in the 2021 quarter compared to $15.96 per barrel in 2020. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas production volumes from continuing operations averaged 348 million cubic feet per day (MMCFD) in the first quarter 2021 compared to 381 MMCFD in 2020.  The decrease of 32 MMCFD was a result of lower volumes in Canada (13 MMCFD), in the Gulf of Mexico (9 MMCFD) and in the Eagle Ford Shale (10 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 and lower capital expenditures throughout 2020 and the effects of a winter storm impacting the Eagle Ford Shale.
Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the 2021 quarter, versus $1.73 per MCF average in the same quarter of 2020.  Average natural gas prices in the US and Canada in the quarter were $3.35 and $2.26 respectively.
Additional details about results of oil and gas operations are presented in the tables on pages 25.
27

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2021 and 2020.
Three Months Ended
March 31,
Barrels per day unless otherwise noted20212020
Continuing operations
Net crude oil and condensate
United StatesOnshore22,165 31,033 
Gulf of Mexico 1
64,363 78,730 
CanadaOnshore6,288 6,833 
Offshore4,589 5,138 
Other70 344 
Total net crude oil and condensate - continuing operations97,475 122,078 
Net natural gas liquids
United StatesOnshore3,933 5,585 
Gulf of Mexico 1
4,679 6,670 
CanadaOnshore1,233 1,401 
Total net natural gas liquids - continuing operations9,845 13,656 
Net natural gas – thousands of cubic feet per day
United StatesOnshore22,016 31,962 
Gulf of Mexico 1
72,658 81,950 
CanadaOnshore253,697 266,848 
Total net natural gas - continuing operations348,371 380,760 
Total net hydrocarbons - continuing operations including NCI 2,3
165,382 199,194 
Noncontrolling interest
Net crude oil and condensate – barrels per day(9,174)(12,020)
Net natural gas liquids – barrels per day(354)(559)
Net natural gas – thousands of cubic feet per day(4,159)(5,091)
Total noncontrolling interest(10,221)(13,428)
Total net hydrocarbons - continuing operations excluding NCI 2,3
155,161 185,767 
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.
28

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains hydrocarbons sold during the three-month periods ended March 31, 2021 and 2020.
Three Months Ended
March 31,
Barrels per day unless otherwise noted20212020
Continuing operations
Net crude oil and condensate
United StatesOnshore22,165 31,033 
Gulf of Mexico 1
62,066 81,002 
CanadaOnshore6,288 6,833 
Offshore3,379 5,175 
Other 313 
Total net crude oil and condensate - continuing operations93,898 124,356 
Net natural gas liquids
United StatesOnshore3,933 5,585 
Gulf of Mexico 1
4,679 6,670 
CanadaOnshore1,233 1,401 
Total net natural gas liquids - continuing operations9,845 13,656 
Net natural gas – thousands of cubic feet per day
United StatesOnshore22,016 31,962 
Gulf of Mexico 1
72,658 81,950 
CanadaOnshore253,697 266,848 
Total net natural gas - continuing operations348,371 380,760 
Total net hydrocarbons - continuing operations including NCI 2,3
161,805 201,472 
Noncontrolling interest
Net crude oil and condensate – barrels per day(8,868)(12,475)
Net natural gas liquids – barrels per day(354)(559)
Net natural gas – thousands of cubic feet per day 2
(4,159)(5,091)
Total noncontrolling interest(9,915)(13,883)
Total net hydrocarbons - continuing operations excluding NCI 2,3
151,890 187,590 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.




29

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month periods ended March 31, 2021 and 2020. Comparative periods are conformed to current presentation.
Three Months Ended
March 31,
20212020
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United StatesOnshore57.41 46.46 
Gulf of Mexico 1
58.78 47.07 
Canada 2
Onshore52.84 37.61 
Offshore59.39 57.27 
Other 65.55 
Natural gas liquids – dollars per barrel
United StatesOnshore21.25 10.79 
Gulf of Mexico 1
23.87 8.28 
Canada 2
Onshore35.92 15.96 
Natural gas – dollars per thousand cubic feet
United StatesOnshore3.27 1.85 
Gulf of Mexico 1
3.39 2.01 
Canada 2
Onshore2.26 1.62 
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 $237.8 million for the first three months of 2021 compared to $392.7 million during the same period in 2020.  The decreased cash from operating activities is primarily attributable to lower revenue from sales to customers ($8.0 million) and higher cash payments made on forward swap commodity contracts (2021: realized loss of $60.9 million; 2020: realized gain of $42.4 million), offset by lower lease operating expense ($62.0 million) and lower general and administrative expense ($7.3 million). For the three months ended March 31, 2021, realized losses on crude oil derivative contracts were $60.9 million (pre-tax) and $48.1 million (post-tax.)
Cash Provided by/ Used in Investing Activities
Cash provided by investing activities was $9.7 million for the first three months of 2021 compared to $376.1 million cash used in the first three months of 2020. On March 17, 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company for previously incurred capital expenditures. Property additions and dry hole costs, which includes amounts expensed, were $258.3 million and $376.1 million in the first three months of 2021 and 2020, respectively. These amounts include $17.7 million and $21.3 million used to fund the development of the King’s Quay FPS in the first three months of 2021 and 2020, respectively. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale to support generating positive free cashflow. See Outlook section on page 32 for further details.
30

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)

Total accrual basis capital expenditures were as follows:
Three Months Ended
March 31,
(Millions of dollars)20212020
Capital Expenditures
Exploration and production$247.3 374.5 
Corporate3.8 3.5 
Total capital expenditures$251.1 378.0 
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Three Months Ended
March 31,
(Millions of dollars)20212020
Property additions and dry hole costs per cash flow statements$240.5 354.8 
Property additions King's Quay per cash flow statements17.7 21.3 
Geophysical and other exploration expenses5.8 11.6 
Capital expenditure accrual changes and other(13.0)(9.7)
Total capital expenditures$251.1 378.0 
Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of significant capital expenditure reductions to support generating positive free cash flow, primarily in the Eagle Ford Shale.
Cash Used in/ Provided by Financing Activities
Net cash used in financing activities was $327.8 million for the first three months of 2021 compared to net cash provided by financing activities of $87.8 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 of the notes due 2022 ($34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($36.0 million), and cash dividends to shareholders ($19.3 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).
As of March 31, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,596.2 million available on its committed RCF.
In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($170.0 million), offset by cash dividends to shareholders ($38.4 million), 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 March 31, 2021 was a deficit of $237.4 million, $208.0 million lower than December 31, 2020, with the decrease primarily attributable to higher accounts payable ($131.2 million), higher other accrued liabilities ($24.0 million), partly offset by a lower cash balance ($79.7 million) and higher accounts receivable ($16.8 million). Higher accounts payable is primarily due to the increase in unrealized losses on crude contracts maturing in the next 12 months.
Capital Employed
At March 31, 2021, long-term debt of $2,755.6 million had decreased by $232.5 million compared to December 31, 2020, 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).  The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 6.3 percent.
31

Table of Contents
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)

A summary of capital employed at March 31, 2021 and December 31, 2020 follows.
March 31, 2021December 31, 2020
(Millions of dollars)Amount%Amount%
Capital employed
Long-term debt$2,755.6 41.2 %$2,988.1 41.5 %
Murphy shareholders' equity3,935.2 58.8 %4,214.3 58.5 %
Total capital employed$6,690.8 100.0 %$7,202.4 100.0 %
Cash and invested cash are maintained in several operating locations outside the United States.  At March 31, 2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $59.8 million in Canada.  In addition, $9.5 million was held in Brunei (which is reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at March 31, 2021).  In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B
Outlook
As discussed in the Summary section on page 22, average crude oil prices continued to recover during the first quarter of 2021 versus the first quarter of 2020 (Q1 2020 WTI: $46.17; Q1 2021 WTI: $57.84). As of close on May 4, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $64.70 and $60.46 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the second quarter, production is expected to average between 160 and 168 MBOEPD, excluding NCI.
The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $725.0 million. Capital and other expenditures will 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 continues to closely monitor the impact of lower commodity prices in 2020 on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company 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 May 4, 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:
CommodityTypeVolumes
(Bbl/d)
Price
(USD/Bbl)
Remaining Period
AreaStart DateEnd Date
United StatesWTI ¹Fixed price derivative swap45,000 $42.77 4/1/202112/31/2021
United StatesWTI ¹Fixed price derivative swap20,000 $44.88 1/1/202212/31/2022
1 West Texas Intermediate
Volumes
(MMcf/d)
Price
(CAD/Mcf)
Remaining Period
AreaCommodityTypeStart DateEnd Date
MontneyNatural GasFixed price forward sales at AECO203 C$2.554/1/20215/31/2021
MontneyNatural GasFixed price forward sales at AECO241 C$2.576/1/202112/31/2021
MontneyNatural GasFixed price forward sales at AECO231 C$2.421/1/20221/31/2022
MontneyNatural GasFixed price forward sales at AECO221 C$2.412/1/20224/30/2022
MontneyNatural GasFixed price forward sales at AECO250 C$2.405/1/20225/31/2022
MontneyNatural GasFixed price forward sales at AECO292 C$2.396/1/202212/31/2022
MontneyNatural GasFixed price forward sales at AECO201 C$2.361/1/202312/31/2023
MontneyNatural GasFixed price forward sales at AECO147 C$2.411/1/202412/31/2024
32

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


Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2020 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 35 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.
33

Table of Contents


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at March 31, 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 $111.3 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 March 31, 2021.
ITEM 4.  CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended March 31, 2021, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
34

Table of Contents
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties.  These risk factors are discussed in Item 1A Risk Factors in its 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 37 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
35

Table of Contents
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
MURPHY OIL CORPORATION
(Registrant)
By/s/ CHRISTOPHER D. HULSE
Christopher D. Hulse
Vice President and Controller
(Chief Accounting Officer and Duly Authorized Officer)
May 6, 2021
(Date)
36

Table of Contents
EXHIBIT INDEX
Exhibit
No.
101. INSXBRL Instance Document
101. SCHXBRL Taxonomy Extension Schema Document
101. CALXBRL Taxonomy Extension Calculation Linkbase Document
101. DEFXBRL Taxonomy Extension Definition Linkbase Document
101. LABXBRL Taxonomy Extension Labels Linkbase Document
101. PREXBRL Taxonomy Extension Presentation Linkbase
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
37