Companies: 10,786     total market cap: $134.829 T
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Murphy Oil
MUR
#2846
Rank
$5.68 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$39.65
Share price
-3.88%
Change (1 day)
43.71%
Change (1 year)
  1. Murphy Oil
  2. Quarterly Reports (10-Q)
  3. Financial Year FY2021 Q3

Murphy Oil - 10-Q quarterly report FY2021 Q3


Text size:
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q  
(Mark One)
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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-20210930_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 October 31, 2021 was 154,459,128.


MURPHY OIL CORPORATION
TABLE OF CONTENTS
Page
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
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
22
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
35
Item 4.  Controls and Procedures
35
36
Item 1.  Legal Proceedings
36
Item 1A.  Risk Factors
36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
36
Item 6.  Exhibits
36
37
1
PART I – FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)
September 30,
2021		December 31,
2020
ASSETS
Current assets
Cash and cash equivalents$505,067 310,606 
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020
186,683 262,014 
Inventories57,411 66,076 
Prepaid expenses40,583 33,860 
Assets held for sale40,987 327,736 
Total current assets830,731 1,000,292 
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020
8,112,093 8,269,038 
Operating lease assets918,719 927,658 
Deferred income taxes442,212 395,253 
Deferred charges and other assets27,101 28,611 
Total assets$10,330,856 10,620,852 
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease$646 — 
Accounts payable615,436 407,097 
Income taxes payable18,035 18,018 
Other taxes payable26,997 22,498 
Operating lease liabilities157,294 103,758 
Other accrued liabilities316,205 150,578 
Liabilities associated with assets held for sale— 14,372 
Total current liabilities1,134,613 716,321 
Long-term debt, including finance lease obligation2,613,703 2,988,067 
Asset retirement obligations797,627 816,308 
Deferred credits and other liabilities723,732 680,580 
Non-current operating lease liabilities781,114 845,088 
Deferred income taxes166,120 180,341 
Total liabilities6,216,909 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 value921,227 941,692 
Retained earnings5,069,578 5,369,538 
Accumulated other comprehensive loss(580,174)(601,333)
Treasury stock(1,656,224)(1,690,661)
Murphy Shareholders' Equity3,949,508 4,214,337 
Noncontrolling interest164,439 179,810 
Total equity4,113,947 4,394,147 
Total liabilities and equity$10,330,856 10,620,852 
See Notes to Consolidated Financial Statements, page 7.
2
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars, except per share amounts)
2021202020212020
Revenues and other income
Revenue from sales to customers$687,549 425,324$2,038,905 1,311,627 
(Loss) gain on derivative instruments(59,164)(5,290)(499,794)319,502 
Gain on sale of assets and other income2,315 1,831 21,217 6,006 
Total revenues and other income630,700 421,865 1,560,328 1,637,135 
Costs and expenses
Lease operating expenses130,131 124,491 403,708 478,283 
Severance and ad valorem taxes11,670 6,781 32,215 22,645 
Transportation, gathering and processing 44,588 41,322 137,196 126,779 
Exploration expenses, including undeveloped lease amortization24,517 12,092 49,840 61,686 
Selling and general expenses27,210 28,509 85,826 104,381 
Restructuring expenses— 4,982 — 46,379 
Depreciation, depletion and amortization189,806 231,603 615,372 769,151 
Accretion of asset retirement obligations12,198 10,778 34,854 31,213 
Impairment of assets— 219,138 171,296 1,206,284 
Other (benefit) expense(32,791)20,224 58,616 (2,957)
Total costs and expenses407,329 699,920 1,588,923 2,843,844 
Operating income (loss) from continuing operations223,371 (278,055)(28,595)(1,206,709)
Other income (loss)
Interest income and other (loss)(1,593)(5,177)(11,459)(10,107)
Interest expense, net(46,925)(45,182)(178,399)(124,877)
Total other loss(48,518)(50,359)(189,858)(134,984)
Income (loss) from continuing operations before income taxes174,853 (328,414)(218,453)(1,341,693)
Income tax expense (benefit)36,838 (62,584)(62,498)(248,890)
Income (loss) from continuing operations138,015 (265,830)(155,955)(1,092,803)
(Loss) from discontinued operations, net of income taxes(706)(778)(600)(6,907)
Net income (loss) including noncontrolling interest137,309 (266,608)(156,555)(1,099,710)
Less: Net income (loss) attributable to noncontrolling interest28,853 (23,055)85,509 (122,869)
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY$108,456 (243,553)$(242,064)(976,841)
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations$0.70 (1.58)$(1.57)(6.31)
Discontinued operations— (0.01)— (0.05)
Net income (loss)$0.70 (1.59)$(1.57)(6.36)
 INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations$0.70 (1.58)$(1.57)(6.31)
Discontinued operations— (0.01)— (0.05)
Net income (loss)$0.70 (1.59)$(1.57)(6.36)
Cash dividends per Common share$0.125 0.125 0.375 0.500 
Average Common shares outstanding (thousands)
Basic154,439 153,596 154,239 153,480 
Diluted155,932 153,596 154,239 153,480 
See Notes to Consolidated Financial Statements, page 7.
3
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)


Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars)2021202020212020
Net income (loss) including noncontrolling interest$137,309 (266,608)$(156,555)(1,099,710)
Other comprehensive (loss) income, net of tax
Net (loss) gain from foreign currency translation(31,308)28,323 6,534 (39,520)
Retirement and postretirement benefit plans4,653 3,726 12,935 (45,219)
Deferred loss on interest rate hedges reclassified to interest expense— 297 1,690 905 
Other comprehensive (loss) income (26,655)32,346 21,159 (83,834)
COMPREHENSIVE INCOME (LOSS)$110,654 (234,262)$(135,396)(1,183,544)
See Notes to Consolidated Financial Statements, page 7.
4
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
Nine Months Ended
September 30,
(Thousands of dollars)20212020
Operating Activities
Net income (loss) including noncontrolling interest$(156,555)(1,099,710)
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities
Loss from discontinued operations600 6,907 
Depreciation, depletion and amortization615,372 769,151 
Dry hole and previously suspended exploration costs 17,899 8,255 
Amortization of undeveloped leases13,872 21,951 
Accretion of asset retirement obligations34,854 31,213 
Impairment of assets171,296 1,206,284 
Noncash restructuring expense— 17,565 
Deferred income tax (benefit) expense(65,149)(231,748)
Mark to market loss (gain) on contingent consideration105,111 (29,476)
Mark to market loss (gain) on derivative instruments228,497 (104,463)
Long-term non-cash compensation42,080 35,200 
Net decrease (increase) in noncash working capital117,330 (26,261)
Other operating activities, net(33,924)(26,837)
Net cash provided by continuing operations activities1,091,283 578,031 
Investing Activities
Property additions and dry hole costs(564,230)(648,725)
Property additions for King's Quay FPS(17,734)(74,936)
Proceeds from sales of property, plant and equipment270,038 — 
Net cash required by investing activities(311,926)(723,661)
Financing Activities
Borrowings on revolving credit facility 165,000 450,000 
Repayment of revolving credit facility (365,000)(250,000)
Retirement of debt(726,358)(12,225)
Debt issuance, net of cost541,913 (613)
Early redemption of debt cost(36,756)— 
Distributions to noncontrolling interest(100,880)(43,673)
Cash dividends paid(57,896)(76,790)
Withholding tax on stock-based incentive awards(4,973)(7,094)
Capital lease obligation payments(643)(514)
Net cash (required) provided by financing activities(585,593)59,091 
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 equivalents697 (585)
Net increase (decrease) in cash and cash equivalents194,461 (87,124)
Cash and cash equivalents at beginning of period310,606 306,760 
Cash and cash equivalents at end of period$505,067 219,636 
1  Net cash provided by discontinued operations is not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 7.
5
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars)
2021202020212020
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued
$— — $— — 
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2021 and 195,100,628 shares at September 30, 2020
Balance at beginning of period195,101 195,101 195,101 195,089 
Exercise of stock options— — — 12 
Balance at end of period195,101 195,101 195,101 195,101 
Capital in Excess of Par Value
Balance at beginning of period915,181 931,429 941,692 949,445 
Exercise of stock options, including income tax benefits(35)— (661)(156)
Restricted stock transactions and other(402)(409)(38,749)(33,649)
Share-based compensation6,483 5,298 18,945 20,678 
Balance at end of period921,227 936,318 921,227 936,318 
Retained Earnings
Balance at beginning of period4,980,428 5,823,426 5,369,538 6,614,304 
Net (loss) attributable to Murphy108,456 (243,553)(242,064)(976,841)
Cash dividends(19,306)(19,200)(57,896)(76,790)
Balance at end of period5,069,578 5,560,673 5,069,578 5,560,673 
Accumulated Other Comprehensive Loss
Balance at beginning of period(553,519)(690,341)(601,333)(574,161)
Foreign currency translation gain (loss), net of income taxes(31,308)28,323 6,534 (39,520)
Retirement and postretirement benefit plans, net of income taxes4,653 3,726 12,935 (45,219)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes— 297 1,690 905 
Balance at end of period(580,174)(657,995)(580,174)(657,995)
Treasury Stock
Balance at beginning of period(1,656,591)(1,691,070)(1,690,661)(1,717,217)
Awarded restricted stock, net of forfeitures343 409 33,888 26,556 
Exercise of stock options24 — 549 — 
Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost
(1,656,224)(1,690,661)(1,656,224)(1,690,661)
Murphy Shareholders’ Equity3,949,508 4,343,436 3,949,508 4,343,436 
Noncontrolling Interest
Balance at beginning of period161,228 204,937 179,810 337,151 
Net income (loss) attributable to noncontrolling interest28,853 (23,055)85,509 (122,869)
Distributions to noncontrolling interest owners(25,642)(11,273)(100,880)(43,673)
Balance at end of period164,439 170,609 164,439 170,609 
Total Equity$4,113,947 4,514,045 $4,113,947 4,514,045 
See Notes to Consolidated Financial Statements, page 7.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/ 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 September 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 September 30, 2021 and December 31, 2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 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 nine-month periods ended September 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.

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 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.
8
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 nine-month periods ended September 30, 2021, the Company recognized $687.5 million and $2,038.9 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and nine-month periods ended September 30, 2020, the Company recognized $425.3 million and $1,311.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars)2021202020212020
Net crude oil and condensate revenue
United States
Onshore$167,010 86,498 464,767 272,284 
                     Offshore340,001 216,918 1,079,418 714,143 
Canada    
Onshore29,110 32,358 89,708 67,268 
Offshore20,499 19,173 70,333 54,864 
Other
— — — 1,806 
Total crude oil and condensate revenue
556,620 354,947 1,704,226 1,110,365 
Net natural gas liquids revenue
United States
Onshore16,356 6,766 33,480 16,145 
 
Offshore11,046 4,765 31,866 13,255 
Canada
Onshore4,501 2,780 11,728 6,090 
Total natural gas liquids revenue
31,903 14,311 77,074 35,490 
Net natural gas revenue
United States
Onshore11,127 4,529 24,442 14,177 
Offshore17,444 9,827 56,855 35,487 
Canada   
Onshore70,455 41,710 176,308 116,108 
Total natural gas revenue
99,026 56,066 257,605 165,772 
Total revenue from contracts with customers687,549 425,324 2,038,905 1,311,627 
(Loss) gain on derivative instruments(59,164)(5,290)(499,794)319,502 
Gain on sale of assets and other income2,315 1,831 21,217 6,006 
Total revenue and other income$630,700 421,865 1,560,328 1,637,135 
Contract Balances and Asset Recognition
As of September 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 $144.0 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 revenue contracts that have financing components as at September 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.
9
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 September 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 September 30, 2021
LocationCommodityEnd DateDescriptionApproximate Volumes
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 CAD fixed prices5 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at USD fixed pricing20 MMCFD
CanadaNatural GasQ4 2023
1
Contracts to sell natural gas at USD index pricing25 MMCFD
CanadaNatural GasQ4 2023Contracts to sell natural gas at CAD fixed prices38 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD index pricing31 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at CAD fixed prices100 MMCFD
CanadaNatural GasQ4 2024
1
Contracts to sell natural gas at CAD fixed prices34 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD fixed pricing15 MMCFD
CanadaNatural GasQ4 2026
1
Contracts to sell natural gas at USD index pricing49 MMCFD
1 These contracts are scheduled to commence after the balance sheet date, at various dates between Q4 2021 and Q1 2022.
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

Note D – Property, Plant, and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of September 30, 2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $186.6 million.  The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2021 and 2020.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)

(Thousands of dollars)20212020
Beginning balance at January 1$181,616 217,326 
Additions pending the determination of proved reserves5,007 9,941 
Capitalized exploratory well costs charged to expense— (39,408)
Balance at September 30$186,623 187,859 
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below).
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.  The projects are aged based on the last well drilled in the project.
September 30,
20212020
(Thousands of dollars)AmountNo. of WellsNo. of ProjectsAmountNo. of WellsNo. of Projects
Aging of capitalized well costs:
Zero to one year$3,297 2 2 8,000 1 — 
One to two years— — — 54,334 5 5 
Two to three years53,078 5 5 — — — 
Three years or more130,248 6 — 125,525 6 — 
$186,623 13 7 187,859 12 5 
Of the $183.3 million of exploratory well costs capitalized more than one year at September 30, 2021, $92.3 million is in Vietnam, $45.0 million is in the U.S., $25.9 million is in Brunei, $15.3 million is in Mexico, and $4.8 million is in Canada.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 
Impairments
During the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans.
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand 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 $1,206.3 million to reduce the carrying values to their estimated fair values at select properties.
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The following table reflects the recognized impairments for the nine months ended September 30, 2021 and 2020.
Nine Months Ended
September 30,
(Thousands of dollars)20212020
U.S.$— 1,152,515 
Canada171,296 — 
Other Foreign— 39,709 
Corporate— 14,060 
$171,296 1,206,284 
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.
11
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 and Malaysian exploration and production operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2021 and 2020 were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars)2021202020212020
Revenues $144 — $801 4,074 
Costs and expenses
Other costs and expenses (benefits)850 778 1,401 10,981 
(Loss) income before taxes(706)(778)(600)(6,907)
Income tax expense— — — — 
(Loss) income from discontinued operations$(706)(778)$(600)(6,907)
As of September 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 $250.1 million (sold in March 2021), the Brunei exploration and production properties, and the Company’s office building in El Dorado, Arkansas.
(Thousands of dollars)September 30,
2021		December 31,
2020
Current assets
Cash$— 10,185 
Inventories— 406 
Property, plant, and equipment, net40,987 307,704 
Deferred income taxes and other assets— 9,441 
Total current assets associated with assets held for sale$40,987 327,736 
Current liabilities
Accounts payable$— 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 September 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 September 30, 2021, the Company had no outstanding borrowings under the RCF and $31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2021, the interest rate in effect on borrowings under the facility was 1.78%. At September 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 $8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022; collectively
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)

the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
In August 2021, the Company redeemed $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 15, 2024.
Subsequent to quarter end, the Company issued a notice of partial redemption with respect to $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to the date of redemption. The redemption date of the 2024 Notes will be December 2, 2021.
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
Nine Months Ended
September 30,
(Thousands of dollars)20212020
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
Decrease in accounts receivable ¹$75,100 251,706 
Decrease in inventories9,718 4,747 
(Increase) in prepaid expenses(6,682)(17,400)
Increase (decrease) in accounts payable and accrued liabilities ¹40,687 (264,078)
(Decrease) in income taxes payable(1,493)(1,236)
Net (increase) decrease in noncash operating working capital$117,330 (26,261)
Supplementary disclosures:
Cash income taxes paid, net of refunds$1,685 (12,559)
Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020
127,793 139,651 
Non-cash investing activities:
Asset retirement costs capitalized ²$36,300 6,342 
Decrease in capital expenditure accrual31,301 74,742 
1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.
2 Excludes non-cash capitalized cost offset by impairment of $74.4 million in the first quarter of 2021 and a gain in other operating income of $71.8 million following a commercial agreement to sanction an asset life extension project at Terra Nova in the third quarter of 2021, which extended the life of Terra Nova by approximately 10 years.


13
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 nine-month periods ended September 30, 2021 and 2020.
Three Months Ended September 30,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2021202020212020
Service cost$1,770 1,664 328 342 
Interest cost4,258 4,827 521 612 
Expected return on plan assets(6,038)(5,773)— — 
Amortization of prior service cost (credit)155 149 — — 
Recognized actuarial loss5,269 5,690 (8)(24)
Net periodic benefit expense$5,414 6,557 841 930 
Nine Months Ended September 30,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2021202020212020
Service cost$5,306 5,996 981 1,235 
Interest cost12,844 16,381 1,563 2,200 
Expected return on plan assets(18,326)(18,414)— — 
Amortization of prior service cost (credit)467 515 — — 
Recognized actuarial loss15,829 14,223 (23)(24)
Net periodic benefit expense$16,120 18,701 2,521 3,411 
Other - curtailment— 586 — (1,825)
Other - special termination benefits— 8,435 — — 
Total net periodic benefit expense$16,120 27,722 2,521 1,586 
The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.
During the nine-month period ended September 30, 2021, the Company made contributions of $31.0 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 $10.9 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. 
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

other stock-based incentives.  The 2020 Long-Term Plan expires in 2030.  A total of five 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 nine months of 2021, the Committee granted the following awards from the 2020 Long-Term Plan:
2020 Long-Term Incentive Plan
Type of AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation 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 nine months of 2021, the Committee granted the following awards to Non-Employee Directors:
2018 Stock Plan for Non-Employee Directors
Type of AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation 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 AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation Methodology
Time Based RSUs 1
5,655 June 10, 2021$23.58 Closing Stock Price at Grant Date
1 Non-employee directors time-based RSUs are scheduled to vest in February 2022.
All stock option exercises are non-cash transactions for the Company.  The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2021.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
Nine Months Ended
September 30,
(Thousands of dollars)20212020
Compensation charged against income before tax benefit$29,145 17,542 
Related income tax benefit recognized in income4,120 2,278 
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Earnings Per Share
Net (loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2021 and 2020.  The following table reports the weighted-average shares outstanding used for these computations.
Three Months Ended September 30,Nine Months Ended
September 30,
(Weighted-average shares)2021202020212020
Basic method154,439,313 153,596,109 154,239,440 153,479,654 
Dilutive stock options and restricted stock units ¹1,492,949 — — — 
Diluted method155,932,262 153,596,109 154,239,440 153,479,654 
1 Due to a net loss recognized by the Company for the nine-month period ended September 30, 2021 and the three-month and nine-month periods ended September 30, 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
Antidilutive stock options excluded from diluted shares1,316,222 2,111,068 1,502,758 2,305,973 
Weighted average price of these options$34.42 $38.54 $34.97 $40.15 

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes.  For the three-month and nine-month periods ended September 30, 2021 and 2020, the Company’s effective income tax rates were as follows:
20212020
Three months ended September 30,21.1%19.1%
Nine months ended September 30,28.6%18.6%
The effective tax rate for the three-month period ended September 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to income generated in Canada, which has a higher tax rate, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax rate on income.
The effective tax rate for the three-month period ended September 30, 2020 was below the statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM.
The effective tax rate for the nine-month period ended September 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 nine-month period ended September 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, and currently the Company is under audit in several of these jurisdictions.  These audits often take multiple years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of September 30, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K– Income Taxes (Contd.)

United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  
Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss and amortized to the income statement over time. During the nine-month period ended September 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.
Commodity Price Risks
The Company has entered into crude oil swaps and collar contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also mature monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.
At September 30, 2021, volumes per day associated with outstanding crude oil derivative contracts and the weighted average prices for these contracts are as follows:
September 30, 2021
20212022
NYMEX WTI swap contracts:
     Volume per day (Bbl):45,000 20,000 
     Price per Bbl:$42.77 $44.88 
NYMEX WTI collar contracts:
     Volume per day (Bbl):— 16,000 
     Price per Bbl:
          Ceiling:$— $71.83 
          Floor: — 60.38 
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at September 30, 2021 and 2020.
At September 30, 2021 and December 31, 2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
September 30, 2021December 31, 2020
(Thousands of dollars)Asset (Liability) DerivativesAsset (Liability) Derivatives
Type of Derivative ContractBalance Sheet LocationFair ValueBalance Sheet LocationFair Value
Commodity swapsAccounts receivable$— Accounts receivable13,050 
Accounts payable(312,448)Accounts payable(89,842)
Deferred credits and other liabilities(41,645)Deferred credits and other liabilities(12,833)
Commodity collarsAccounts receivable— Accounts receivable— 
Accounts payable(15,929)Accounts payable— 
For the three-month and nine-month periods ended September 30, 2021 and 2020, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
Gain (Loss)Gain (Loss)
(Thousands of dollars)Statement of Operations LocationThree Months Ended September 30,Nine months ended September 30,
Type of Derivative Contract2021202020212020
Commodity swaps(Loss) gain on derivative instruments$(43,235)(5,290)(483,865)319,502 
Commodity collars(Loss) gain on derivative instruments(15,929)— (15,929)— 
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2021 and December 31, 2020, are presented in the following table.
September 30, 2021December 31, 2020
(Thousands of dollars)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:
Commodity swaps$— — — — — 13,050 — 13,050 
$— — — — — 13,050 — 13,050 
Liabilities:
Commodity collars$— 15,929 — 15,929 — — — — 
Nonqualified employee savings plan17,180 — — 17,180 14,988 — — 14,988 
Commodity swaps— 354,093 — 354,093 — 102,675 — 102,675 
Contingent consideration— — 238,115 238,115 — — 133,004 133,004 
$17,180 370,022 238,115 625,317 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 derivative instruments in the Consolidated Statements of Operations. 
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations. 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
The contingent consideration, related to 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 September 30, 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 September 30, 2021 and the changes during the nine-month period ended September 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 earnings6,534 — — 6,534 
Reclassifications to income— 12,935 ¹1,690 ²14,625 
Net other comprehensive income (loss)6,534 12,935 1,690 21,159 
Balance at September 30, 2021$(317,477)(262,697)— (580,174)
1 Reclassifications before taxes of $16,282 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2021.  See Note H for additional information.  Related income taxes of $3,347 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2021.
2 Reclassifications before taxes of $2,140 are included in Interest expense, net, for the nine-month period ended September 30, 2021.  Related income taxes of $450 are included in Income tax expense (benefit) for the nine-month period ended September 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, HEALTH AND SAFETY MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and
safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.

Violation of environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)

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

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. 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.

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.
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Total Assets at September 30, 2021Three Months Ended September 30, 2021Three Months Ended September 30, 2020
(Millions of dollars)External
Revenues		Income
(Loss)		External
Revenues		Income
(Loss)
Exploration and production ¹
United States$6,586.3 565.2 168.1 330.8 (172.6)
Canada2,241.2 124.6 73.9 96.3 (8.6)
Other264.6 — (5.2)— (11.7)
Total exploration and production9,092.1 689.8 236.8 427.1 (192.9)
Corporate1,237.8 (59.1)(98.8)(5.2)(72.9)
Continuing operations10,329.9 630.7 138.0 421.9 (265.8)
Discontinued operations, net of tax1.0 — (0.7)— (0.8)
Total$10,330.9 630.7 137.3 421.9 (266.6)
Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
(Millions of dollars)External
Revenues		Income
(Loss)		External
Revenues		Income
(Loss)
Exploration and production ¹
United States1,704.4 481.8 1,070.6 (1,011.7)
Canada349.2 (37.7)245.2 (35.0)
Other— (22.5)1.8 (73.0)
Total exploration and production2,053.6 421.6 1,317.6 (1,119.7)
Corporate(493.3)(577.6)319.5 26.9 
Continuing operations1,560.3 (156.0)1,637.1 (1,092.8)
Discontinued operations, net of tax— (0.6)— (6.9)
Total1,560.3 (156.6)1,637.1 (1,099.7)
1 Additional details about results of oil and natural gas operations are presented in the table on pages 25 and 26.
21

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary
In 2021, the global distribution and administration of vaccinations in response to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to an improving global economic outlook and subsequently increased demand for oil and gas. Emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the outlook, however in 2021 demand for oil and gas has remained resilient. The demand resilience has revealed an oil supply shortage, and hence is applying upward pressure to current and future oil and gas prices.
The OPEC+ group of oil producing countries (OPEC+) continues to target increasing supply by 0.4 million bpd a month, with aims to fully phase out prior cuts by September 2022, at the current rate of OPEC+ supply increases. In 2020 OPEC+ cut production by 10 million barrels per day (bpd) following the COVID-19 demand reduction. It has gradually reinstated supply so that the curtailments are approximately 5.8 million bpd at the end of September 2021. However, some members of the OPEC+ are falling short on supply increases.
Overall, the combination of OPEC+ supply constraints and the increase in demand driven by the global COVID-19 vaccine roll out has provided upward pressure to the oil price which directly impacts the Company’s product revenue from sales compared to one year ago.
For the three months ended September 30, 2021, West Texas Intermediate (WTI) crude oil prices averaged approximately $70.56 per barrel (compared to $66.07 in the second quarter of 2021 and $40.93 in the third quarter of 2020). The closing price for WTI at the end of the third quarter of 2021 was approximately $71.54 per barrel, reflecting a modest increase from the second quarter 2021 closing price and an 81% increase from the third quarter 2020 closing price. The average price in October 2021 was $81.22 per barrel. As of close on November 2, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $83.91 and $76.27 per barrel, respectively.
In the third quarter of 2021, the Company continued to delever by redeeming $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 for the principal amount plus cash costs of $2.6 million. Earlier in 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which included redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and closing costs of $8.1 million. The proceeds from issue are reported net of costs to issue on the Consolidated Balance Sheets.
In the third quarter of 2021, the Company acquired an additional 7.525% working interest at Terra Nova in Canada following a commercial agreement to sanction an asset life extension project. This transaction deferred an asset obligation at Terra Nova by approximately 10 years and decreased the obligation associated with the abandonment liability of the working interest before the acquisition by approximately $72 million.
For the three months ended September 30, 2021, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 14.5 thousand barrels of oil equivalent per day (including NCI).  The Company invested $110.5 million in capital expenditures (on a value of work done basis) in the three months ended September 30, 2021. The Company reported net income from continuing operations of $138.0 million for the three months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of $28.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $44.1 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on contingent consideration of $22.4 million.
For the nine months ended September 30, 2021, the Company produced 170 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI).  The Company invested $568.7 million in capital expenditures (on a value of work done basis) in the nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay Floating Production System (FPS). The FPS capital expenditures were reimbursed by Arclight in the first quarter of 2021 (see below). The Company reported net loss from continuing operations of $156.0 million for the nine months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of $85.5 million, after-tax impairment charges of $128.0 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on unrealized mark to market revaluations on commodity price swap and collar positions and contingent consideration of $180.5 million and $83.0 million, respectively.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Summary (contd.)
For the three months ended September 30, 2020, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.  The Company invested $122.7 million in capital expenditures (on a value of work done basis), in the third quarter of 2020, which included $19.3 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $265.8 million for the third quarter of 2020. This amount included loss attributable to noncontrolling interest of $23.1 million, after-tax impairment charges of $145.9 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $54.8 million and $11.1 million, respectively.
For the nine months ended September 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $680.3 million in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2020, which included $80.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $1,092.8 million for the nine months ended September 30, 2020. This amount included loss attributable to noncontrolling interest of $122.9 million, after-tax impairment charges of $854.2 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $82.5 million and $23.3 million, respectively.
In the first quarter, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the 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.
Results of Operations
Murphy’s income (loss) by type of business is presented below.
Income (Loss)
Three Months Ended September 30,Nine Months Ended September 30,
(Millions of dollars)2021202020212020
Exploration and production$236.8 (192.9)421.6 (1,119.7)
Corporate and other(98.8)(72.9)(577.6)26.9 
Income (loss) from continuing operations138.0 (265.8)(156.0)(1,092.8)
Discontinued operations ¹(0.7)(0.8)(0.6)(6.9)
Net income (loss) including noncontrolling interest$137.3 (266.6)(156.6)(1,099.7)
1 The Company has presented its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations in its consolidated financial statements. 
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
Income (Loss)
Three Months Ended
September 30,		Nine Months Ended September 30,
(Millions of dollars)2021202020212020
Exploration and production
United States$168.1 (172.6)481.8 (1,011.7)
Canada73.9 (8.6)(37.7)(35.0)
Other (5.2)(11.7)(22.5)(73.0)
Total$236.8 (192.9)421.6 (1,119.7)

23
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars, except per barrel of oil equivalents sold)
2021202020212020
Net income (loss) attributable to Murphy (GAAP)$108.5 (243.6)(242.1)(976.8)
Income tax expense (benefit)36.8 (62.6)(62.5)(248.9)
Interest expense, net46.9 45.2 178.4 124.9 
Depreciation, depletion and amortization expense ¹182.8 219.7 588.4 725.1 
EBITDA attributable to Murphy (Non-GAAP)375.0 (41.3)462.2 (375.7)
Mark-to-market (gain) loss on derivative instruments(55.9)69.3 228.5 (104.5)
Impairment of assets ¹— 186.5 171.3 1,072.5 
Mark-to-market loss (gain) on contingent consideration28.4 14.0 105.1 (29.5)
Asset retirement obligation (gains) losses(71.8)— (71.8)— 
Accretion of asset retirement obligations ¹10.8 10.8 30.8 31.2 
Unutilized rig charges3.2 5.2 8.5 13.2 
Foreign exchange (gains) losses(2.8)0.8 (1.5)(2.5)
Discontinued operations loss0.7 0.8 0.6 6.9 
Restructuring expenses— 5.0 — 46.4 
Inventory loss— — — 4.8 
Seal insurance proceeds— (1.7)— (1.7)
Adjusted EBITDA attributable to Murphy (Non-GAAP)$287.6 249.4 933.7 661.1 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)14,219 14,166 43,536 46,478 
Adjusted EBITDA per barrel of oil equivalents sold$20.23 17.61 21.45 14.22 
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.

24
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020
(Millions of dollars)
United
States 1
CanadaOtherTotal
Three Months Ended September 30, 2021
Oil and gas sales and other operating revenues$565.2 124.6 — 689.8 
Lease operating expenses96.7 33.4 0.1 130.2 
Severance and ad valorem taxes10.8 0.8 — 11.6 
Transportation, gathering and processing28.4 16.2 — 44.6 
Depreciation, depletion and amortization147.0 39.7 0.1 186.8 
Accretion of asset retirement obligations9.3 2.9 — 12.2 
Exploration expenses
Dry holes and previously suspended exploration costs17.3 — — 17.3 
Geological and geophysical— — 0.3 0.3 
Other exploration1.3 0.1 0.5 1.9 
18.6 0.1 0.8 19.5 
Undeveloped lease amortization3.1 0.1 1.8 5.0 
Total exploration expenses21.7 0.2 2.6 24.5 
Selling and general expenses4.2 4.0 1.2 9.4 
Other ²39.1 (71.7)2.0 (30.6)
Results of operations before taxes208.0 99.1 (6.0)301.1 
Income tax provisions (benefits)39.9 25.2 (0.8)64.3 
Results of operations (excluding Corporate segment)$168.1 73.9 (5.2)236.8 
Three Months Ended September 30, 2020
Oil and gas sales and other operating revenues$330.8 96.3 — 427.1 
Lease operating expenses91.5 32.6 0.4 124.5 
Severance and ad valorem taxes6.4 0.3 — 6.7 
Transportation, gathering and processing29.3 12.0 — 41.3 
Depreciation, depletion and amortization166.2 59.6 0.5 226.3 
Accretion of asset retirement obligations9.4 1.4 — 10.8 
Impairment of assets205.1 — — 205.1 
Exploration expenses
Dry holes and previously suspended exploration costs0.6 — — 0.6 
Geological and geophysical0.1 — (0.1)— 
Other exploration0.6 0.1 3.6 4.3 
1.3 0.1 3.5 4.9 
Undeveloped lease amortization4.9 0.1 2.3 7.3 
Total exploration expenses6.2 0.2 5.8 12.2 
Selling and general expenses5.3 3.4 1.6 10.3 
Other22.5 (1.5)2.5 23.5 
Results of operations before taxes(211.1)(11.7)(10.8)(233.6)
Income tax (benefits) provisions (38.5)(3.1)0.9 (40.7)
Results of operations (excluding Corporate segment)$(172.6)(8.6)(11.7)(192.9)
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.

25
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020
(Millions of dollars)
United
States 1
CanadaOtherTotal
Nine Months Ended September 30, 2021
Oil and gas sales and other operating revenues$1,704.4 349.2 — 2,053.6 
Lease operating expenses303.3 100.0 0.4 403.7 
Severance and ad valorem taxes30.6 1.6 — 32.2 
Transportation, gathering and processing90.5 46.7 — 137.2 
Depreciation, depletion and amortization476.6 128.0 1.1 605.7 
Accretion of asset retirement obligations27.5 7.4 — 34.9 
Impairment of assets— 171.3 — 171.3 
Exploration expenses
Dry holes and previously suspended exploration costs17.9 — — 17.9 
Geological and geophysical2.7 — 1.3 4.0 
Other exploration4.2 0.2 9.6 14.0 
24.8 0.2 10.9 35.9 
Undeveloped lease amortization7.9 0.2 5.8 13.9 
Total exploration expenses32.7 0.4 16.7 49.8 
Selling and general expenses15.0 12.0 4.7 31.7 
Other ²133.5 (67.7)(1.2)64.6 
Results of operations before taxes594.7 (50.5)(21.7)522.5 
Income tax provisions (benefits)112.9 (12.8)0.8 100.9 
Results of operations (excluding Corporate segment)$481.8 (37.7)(22.5)421.6 
Nine months ended September 30, 2020
Oil and gas sales and other operating revenues$1,070.6 245.2 1.8 1,317.6 
Lease operating expenses386.5 90.6 1.2 478.3 
Severance and ad valorem taxes21.6 1.0 — 22.6 
Transportation, gathering and processing95.4 31.4 — 126.8 
Depreciation, depletion and amortization589.5 161.3 1.5 752.3 
Accretion of asset retirement obligations27.1 4.1 — 31.2 
Impairment of assets1,152.5 — 39.7 1,192.2 
Exploration expenses
Dry holes and previously suspended exploration costs8.3 — — 8.3 
Geological and geophysical9.4 0.1 4.1 13.6 
Other exploration4.3 0.4 13.1 17.8 
22.0 0.5 17.2 39.7 
Undeveloped lease amortization14.8 0.3 6.9 22.0 
Total exploration expenses36.8 0.8 24.1 61.7 
Selling and general expenses16.6 13.2 5.5 35.3 
Other1.0 (2.5)1.4 (0.1)
Results of operations before taxes(1,256.4)(54.7)(71.6)(1,382.7)
Income tax provisions (benefits)(244.7)(19.7)1.4 (263.0)
Results of operations (excluding Corporate segment)$(1,011.7)(35.0)(73.0)(1,119.7)
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the nine months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.
26
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Exploration and Production
Third 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 $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of 2020.  Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A: $19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in the third quarter of 2020. Lower impairment charges were due to impairment charges recognized in the prior period related to Gulf of Mexico Cascade & Chinook field and no such charges in current period. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. 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) related to prior Gulf of Mexico (GOM) acquisitions. Higher exploration expense is primarily due to dry hole costs related to Silverback in the current period.
Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter of 2020. Results were favorable $82.5 million compared to the 2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($28.3 million) and lower DD&A ($19.9 million), partially offset by higher tax expense ($28.3 million) and higher transportation, gathering and processing ($4.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Montney. Lower DD&A is due to lower production volumes at Kaybob Duvernay due to normal well decline. Higher 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 $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020.  The result was $6.5 million favorable in the 2021 period versus 2020 primarily due lower exploration expenses in Brazil and Mexico.
Nine 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 $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020.  Results were $1,493.5 million favorable in 2021 period compared to the 2020 period primarily due to no impairment charges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($633.8 million), lower DD&A ($112.9 million), lower lease operating expenses (LOE: $83.2 million), partially offset by higher income tax expense ($357.6 million) and higher other operating expense ($132.5 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 lower 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. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in 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 GOM workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). Higher income tax expense is a result of higher pre-tax income principally due to higher 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 ($105.1 million; as a result of higher commodity prices) from prior GOM acquisitions.
Canadian E&P operations reported a loss of $37.7 million in the first nine months of 2021 compared to a loss of $35.0 million in the first nine months of 2020.  Results were comparable year over year. 2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue ($104.0 million) and lower DD&A ($33.3 million) offset by higher transportation, gathering and processing expenses ($15.3 million) and lease operating expenses ($9.4 million). Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital
27
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss of $22.5 million in the first nine months of 2021 compared to a loss of $73.0 million in the prior year. Results were $50.5 million favorable compared to the 2020 period primarily due to no repeat of an impairment charge of $39.7 million in the prior year.
Corporate
Third quarter 2021 vs. 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020. The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $59.2 million loss; 2020: $5.3 million loss), partially offset by lower impairment charges ($14.1 million), higher tax benefits ($5.7 million), lower restructuring charges ($5.0 million), and lower DD&A ($2.3 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.
Nine months 2021 vs. 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $577.6 million in the first nine months of 2021 compared to earnings of $26.9 million in the first nine months of 2020. The $604.5 million unfavorable variance is primarily due to realized and unrealized losses on derivative instruments in 2021 compared to gains in 2020 (2021: $499.8 million loss; 2020: $319.5 million gain), and higher interest expense ($54.1 million), partially offset by higher tax benefits ($177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $74.87 and for 2022 was $70.87 (versus swap contract fixed hedge prices of $42.77 and $44.88, respectively). Interest charges are higher in 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 benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

Production Volumes and Prices
Third quarter 2021 vs. 2020
Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020. U.S. Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms. The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020.
Average crude oil and condensate production from continuing operations was 88,245 barrels per day in the third quarter of 2021 compared to 95,391 barrels per day in the third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to Kaybob Duvernay well decline), lower volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a
28
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

worldwide basis, the Company’s crude oil and condensate prices averaged $68.88 per barrel in the third quarter 2021 compared to $39.79 per barrel in the 2020 period, an increase of 73% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 10,391 barrels per day in the third quarter 2021 compared to 10,523 barrels per day in the 2020 period. The average sales price for U.S. NGL was $32.01 per barrel in the 2021 quarter compared to $13.91 per barrel in 2020. The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in 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 387.5 million cubic feet per day (MMCFD) in the third quarter 2021 compared to 341.5 MMCFD in 2020.  The increase of 46 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico (7 MMCFD) and in the Eagle Ford Shale (4 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. Lower volumes in the Gulf of Mexico are principally due to facility shut-ins as a result of Hurricane Ida.
Natural gas prices for the total Company averaged $2.78 per thousand cubic feet (MCF) in the 2021 quarter, versus $1.78 per MCF average in the same quarter of 2020.  Average natural gas prices in the U.S. and Canada in the quarter were $3.99 and $2.47 per MCF, respectively.
Nine months 2021 vs. 2020
Total hydrocarbon production from all E&P continuing operations averaged 170,209 barrels of oil equivalent per day in the first nine months of 2021, which represented a 6% decrease from the 180,443 barrels per day produced in the first nine 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 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020. The decrease of 10,364 barrels per day was principally due to lower Gulf of Mexico production (5,472 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 and facility shut-ins as a result of Hurricane Ida in the third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged $64.19 per barrel in the first nine months of 2021 compared to $36.88 per barrel in the 2020 period, an increase of 74% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,498 barrels per day in the first nine months of 2021 compared to 11,901 barrels per day in the 2020 period.  The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in 2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 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 368.4 million cubic feet per day (MMCFD) in the first nine months of 2021 compared to 359.2 MMCFD in 2020.  The increase of 9.2 MMCFD was primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the first nine months of 2021, versus $1.68 per MCF average in the same period of 2020.  Average natural gas prices in the U.S. and Canada in the quarter were $3.26 and $2.33, respectively.
Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26.
29
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2021 and 2020.
Three Months Ended
September 30,		Nine Months Ended
September 30,
Barrels per day unless otherwise noted2021202020212020
Continuing operations
Net crude oil and condensate
United StatesOnshore26,193 24,851 26,552 27,945 
Gulf of Mexico 1
53,011 56,517 61,905 67,377 
CanadaOnshore4,963 9,595 5,598 8,106 
Offshore3,779 4,428 4,016 5,136 
Other299 — 243 114 
Total net crude oil and condensate - continuing operations88,245 95,391 98,314 108,678 
Net natural gas liquids
United StatesOnshore5,847 5,489 5,043 5,459 
Gulf of Mexico 1
3,459 3,521 4,296 5,131 
CanadaOnshore1,085 1,513 1,159 1,311 
Total net natural gas liquids - continuing operations10,391 10,523 10,498 11,901 
Net natural gas – thousands of cubic feet per day
United StatesOnshore31,478 27,520 27,750 29,054 
Gulf of Mexico 1
46,339 53,046 63,557 67,850 
CanadaOnshore309,709 260,895 277,077 262,279 
Total net natural gas - continuing operations387,526 341,461 368,384 359,183 
Total net hydrocarbons - continuing operations including NCI 2,3
163,224 162,824 170,209 180,443 
Noncontrolling interest
Net crude oil and condensate – barrels per day(7,546)(9,298)(8,834)(10,674)
Net natural gas liquids – barrels per day(243)(327)(322)(443)
   Net natural gas – thousands of cubic feet per day 2
(2,331)(3,269)(3,498)(4,137)
Total noncontrolling interest(8,178)(10,170)(9,739)(11,807)
Total net hydrocarbons - continuing operations excluding NCI 2,3
155,046 152,654 160,470 168,636 
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.





30
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 2021 and 2020. Comparative periods are conformed to current presentation.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United StatesOnshore69.30 37.83 64.16 35.56 
Gulf of Mexico 1
68.93 40.82 64.44 38.08 
Canada 2
Onshore63.76 36.65 58.70 30.29 
Offshore72.64 43.81 68.93 37.85 
Other— — — 63.51 
Natural gas liquids – dollars per barrel
United StatesOnshore30.37 13.39 24.29 10.78 
Gulf of Mexico 1
34.71 14.71 27.17 9.43 
Canada 2
Onshore45.12 19.97 37.05 16.95 
Natural gas – dollars per thousand cubic feet
United StatesOnshore3.85 1.78 3.23 1.76 
Gulf of Mexico 1
4.09 2.01 3.28 1.91 
Canada 2
Onshore2.47 1.74 2.33 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 $1,091.3 million for the first nine months of 2021 compared to $578.0 million during the same period in 2020.  The increased cash from operating activities is primarily attributable to higher revenue from sales to customers ($727.3 million), lower working capital ($143.6 million), lower lease operating expense ($74.6 million), and lower general and administrative and cash restructuring expense ($47.4 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $271.3 million; 2020: realized gain of $215.0 million).
Cash Required by Investing Activities
Net cash required by investing activities was $311.9 million for the first nine months of 2021 compared to $723.7 million during the same period in 2020. Property additions and dry hole costs, which includes amounts expensed, were $582.0 million and $723.7 million in the first nine months of 2021 and 2020, respectively. These amounts include $17.7 million and $74.9 million used to fund the development of the King’s Quay FPS in the first nine months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed 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:
Nine Months Ended
September 30,
(Millions of dollars)20212020
Capital Expenditures
Exploration and production$556.0 671.0 
Corporate12.7 9.3 
Total capital expenditures$568.7 680.3 
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Nine Months Ended
September 30,
(Millions of dollars)20212020
Property additions and dry hole costs per cash flow statements$564.2 648.7 
Property additions King's Quay per cash flow statements17.7 74.9 
Geophysical and other exploration expenses13.3 26.8 
Capital expenditure accrual changes and other(26.6)(70.2)
Total capital expenditures$568.7 680.3 
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 $585.6 million for the first nine months of 2021 compared to net cash provided by financing activities of $59.1 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 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).
As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.
In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($450.0 million), offset by repayments on the revolving credit facility ($250.0 million), cash dividends to shareholders ($76.8 million), and distributions to our noncontrolling interest ($43.7 million).
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2021 was a deficit of $344.9 million, $315.5 million lower than December 31, 2020, with the decrease primarily attributable to higher accounts payable ($208.3 million), higher other accrued liabilities ($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a higher cash balance ($194.5 million) and lower accounts receivable ($75.3 million). Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS. Lower accounts receivable are principally due to the timing of cash received from our joint venture partners to fund joint operations.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)

Capital Employed
At September 30, 2021, long-term debt of $2,613.7 million had decreased by $374.4 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021.  The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.
A summary of capital employed at September 30, 2021 and December 31, 2020 follows.
September 30, 2021December 31, 2020
(Millions of dollars)Amount%Amount%
Capital employed
Long-term debt$2,613.7 39.8 %$2,988.1 41.5 %
Murphy shareholders' equity3,949.5 60.2 %4,214.3 58.5 %
Total capital employed$6,563.2 100.0 %$7,202.4 100.0 %
Cash and invested cash are maintained in several operating locations outside the United States.  At September 30, 2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $119.4 million in Canada and $6.2 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 half of 2021 versus 2020 (Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93). As of close on November 2, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $83.91 and $76.27 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 fourth quarter, production is expected to average between 145.5 and 153.5 MBOEPD, excluding noncontrolling interest (NCI).
The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $685.0 million. Capital and other expenditures are routinely reviewed 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 remaining 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.
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 of the vaccination roll-outs globally.
As of November 2, 2021, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
CommodityTypeVolumes
(Bbl/d)		Price
(USD/Bbl)		Remaining Period
AreaStart DateEnd Date
United StatesWTI ¹Fixed price derivative swap45,000 $42.77 10/1/202112/31/2021
United StatesWTI ¹Fixed price derivative swap20,000 $44.88 1/1/202212/31/2022

Volumes
(Bbl/d)		Average
Put
(USD/Bbl)
Average
Call
(USD/Bbl)		Remaining Period
AreaCommodityTypeStart DateEnd Date
United StatesWTI ¹Derivative collars23,000 $62.652 $74.774 1/1/202212/31/2022
1 West Texas Intermediate

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

Volumes
(MMcf/d)		Price/McfRemaining Period
AreaCommodityTypeStart DateEnd Date
MontneyNatural GasFixed price forward sales 196 C$2.5510/1/202112/31/2021
MontneyNatural GasFixed price forward sales 186 C$2.361/1/20221/31/2022
MontneyNatural GasFixed price forward sales 176 C$2.342/1/20224/30/2022
MontneyNatural GasFixed price forward sales 205 C$2.345/1/20225/31/2022
MontneyNatural GasFixed price forward sales 247 C$2.346/1/202210/31/2022
MontneyNatural GasFixed price forward sales 266 C$2.3611/1/202212/31/2022
MontneyNatural GasFixed price forward sales 269 C$2.351/1/20233/31/2023
MontneyNatural GasFixed price forward sales 250 C$2.354/1/202312/31/2023
MontneyNatural GasFixed price forward sales 162 C$2.391/1/202412/31/2024
MontneyNatural GasFixed price forward sales 45 US$2.0510/1/202112/31/2022
MontneyNatural GasFixed price forward sales25 US$1.981/1/202310/31/2024
MontneyNatural GasFixed price forward sales15 US$1.9811/1/202412/31/2024
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 September 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 $113.6 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 September 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 September 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.
35
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.
36
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
MURPHY OIL CORPORATION
(Registrant)
By/s/ CHRISTOPHER D. HULSE
Christopher D. Hulse
Vice President and Controller
(Chief Accounting Officer and Duly Authorized Officer)
November 4, 2021
(Date)
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EXHIBIT INDEX
The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.
Exhibit
No.
*31.1
*31.2
*32
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

38

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