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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, 2020
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-20200930_G1.JPG
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 71-0361522
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-200 77024
Houston, Texas (Zip Code)
(Address of principal executive offices)
(281)
675-9000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 Title of each class Trading Symbol Name of each exchange on which registered
Common Stock, $1.00 Par Value MUR New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes    ☐ No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.
Large accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at October 31, 2020 was 153,598,625.


MURPHY OIL CORPORATION
TABLE OF CONTENTS
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1
PART I – FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)
September 30,
2020 		December 31,
2019
ASSETS
Current assets
Cash and cash equivalents $ 219,636  306,760 
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019
279,149  426,684 
Inventories 67,856  76,123 
Prepaid expenses 58,099  40,896 
Assets held for sale 108,916  123,864 
Total current assets 733,656  974,327 
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,102,285 in 2020 and $9,333,646 in 2019
8,592,834  9,969,743 
Operating lease assets 765,484  598,293 
Deferred income taxes 347,053  129,287 
Deferred charges and other assets 30,324  46,854 
Total assets $ 10,469,351  11,718,504 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 295,398  602,096 
Income taxes payable 17,813  19,049 
Other taxes payable 23,755  18,613 
Operating lease liabilities 100,169  92,286 
Other accrued liabilities 157,574  197,447 
Liabilities associated with assets held for sale 14,677  13,298 
Total current liabilities 609,386  942,789 
Long-term debt, including capital lease obligation 2,987,057  2,803,381 
Asset retirement obligations 856,856  825,794 
Deferred credits and other liabilities 635,980  613,407 
Non-current operating lease liabilities 686,516  521,324 
Deferred income taxes 179,511  207,198 
Total liabilities 5,955,306  5,913,893 
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 2020 and 195,089,269 shares in 2019
195,101  195,089 
Capital in excess of par value 936,318  949,445 
Retained earnings 5,560,673  6,614,304 
Accumulated other comprehensive loss (657,995) (574,161)
Treasury stock (1,690,661) (1,717,217)
Murphy Shareholders' Equity 4,343,436  5,467,460 
Noncontrolling interest 170,609  337,151 
Total equity 4,514,045  5,804,611 
Total liabilities and equity $ 10,469,351  11,718,504 
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)
2020 2019 2020 2019
Revenues and other income
Revenue from sales to customers $ 425,324  750,337 1,311,627  2,060,127 
(Loss) gain on crude contracts (5,290) 63,247  319,502  121,163 
Gain on sale of assets and other income 1,831  3,493  6,006  10,283 
Total revenues and other income 421,865  817,077  1,637,135  2,191,573 
Costs and expenses
Lease operating expenses 124,491  147,632  478,283  416,460 
Severance and ad valorem taxes 6,781  13,803  22,645  36,972 
Transportation, gathering and processing 41,322  54,305  126,779  128,748 
Exploration expenses, including undeveloped lease amortization 12,092  12,358  61,686  75,570 
Selling and general expenses 28,509  55,366  104,381  176,258 
Restructuring expenses 4,982  —  46,379  — 
Depreciation, depletion and amortization 231,603  325,562  769,151  819,270 
Accretion of asset retirement obligations 10,778  10,587  31,213  29,824 
Impairment of assets 219,138  —  1,206,284  — 
Other (benefit) expense 20,224  (29,000) (2,957) 26,442 
Total costs and expenses 699,920  590,613  2,843,844  1,709,544 
Operating (loss) income from continuing operations (278,055) 226,464  (1,206,709) 482,029 
Other (loss)
Interest and other (loss) (5,177) (4,418) (10,107) (18,134)
Interest expense, net (45,182) (44,930) (124,877) (145,095)
Total other (loss) (50,359) (49,348) (134,984) (163,229)
(Loss) income from continuing operations before income taxes (328,414) 177,116  (1,341,693) 318,800 
Income tax (benefit) expense (62,584) 18,782  (248,890) 38,719 
(Loss) income from continuing operations (265,830) 158,334  (1,092,803) 280,081 
(Loss) income from discontinued operations, net of income taxes (778) 953,368  (6,907) 1,027,632 
Net (loss) income including noncontrolling interest (266,608) 1,111,702  (1,099,710) 1,307,713 
Less: Net (loss) income attributable to noncontrolling interest (23,055) 22,700  (122,869) 86,257 
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY $ (243,553) 1,089,002  (976,841) 1,221,456 
(LOSS) INCOME PER COMMON SHARE – BASIC
Continuing operations $ (1.58) 0.85  (6.31) 1.16 
Discontinued operations (0.01) 5.94  (0.05) 6.14 
Net (loss) income $ (1.59) 6.79  (6.36) 7.30 
(LOSS) INCOME PER COMMON SHARE – DILUTED
Continuing operations $ (1.58) 0.84  (6.31) 1.16 
Discontinued operations (0.01) 5.92  (0.05) 6.11 
Net (loss) income $ (1.59) 6.76  (6.36) 7.27 
Cash dividends per Common share 0.125  0.25  0.50  0.75 
Average Common shares outstanding (thousands)
Basic 153,596  160,366  153,480  167,310 
Diluted 153,596  160,980  153,480  168,105 
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) 2020 2019 2020 2019
Net (loss) income including noncontrolling interest $ (266,608) 1,111,702  (1,099,710) 1,307,713 
Other comprehensive (loss) income, net of tax
Net (loss) gain from foreign currency translation 28,323  (17,128) (39,520) 36,927 
Retirement and postretirement benefit plans 3,726  2,761  (45,219) 8,277 
Deferred loss on interest rate hedges reclassified to interest expense 297  585  905  1,756 
Other comprehensive (loss) income 32,346  (13,782) (83,834) 46,960 
COMPREHENSIVE (LOSS) INCOME $ (234,262) 1,097,920  (1,183,544) 1,354,673 
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) 2020 2019
Operating Activities
Net (loss) income including noncontrolling interest $ (1,099,710) 1,307,713 
Adjustments to reconcile net (loss) income to net cash provided by continuing operations activities:
Loss (income) from discontinued operations 6,907  (1,027,632)
Depreciation, depletion and amortization 769,151  819,270 
Previously suspended exploration costs 8,255  12,901 
Amortization of undeveloped leases 21,951  21,680 
Accretion of asset retirement obligations 31,213  29,824 
Impairment of assets 1,206,284  — 
Noncash restructuring expense 17,565  — 
Deferred income tax (benefit) expense (231,748) 50,597 
Mark to market (gain) loss on contingent consideration (29,476) 512 
Mark to market (gain) loss on crude contracts (104,463) (100,076)
Long-term non-cash compensation 35,200  60,567 
Net decrease (increase) in noncash operating working capital (26,261) 40,257 
Other operating activities, net (26,837) (62,386)
Net cash provided by continuing operations activities 578,031  1,153,227 
Investing Activities
Property additions and dry hole costs (648,725) (995,509)
Property additions for King's Quay FPS (74,936) (13,637)
Acquisition of oil and gas properties —  (1,212,949)
Proceeds from sales of property, plant and equipment —  19,072 
Net cash required by investing activities (723,661) (2,203,023)
Financing Activities
Borrowings on revolving credit facility 450,000  1,575,000 
Repayment of revolving credit facility (250,000) (1,900,000)
Cash dividends paid (76,790) (125,437)
Distributions to noncontrolling interest (43,673) (97,510)
Early retirement of debt (12,225) — 
Withholding tax on stock-based incentive awards (7,094) (6,991)
Debt issuance, net of cost (613) — 
Capital lease obligation payments (514) (510)
Repurchase of common stock —  (405,938)
Net cash (required) provided by financing activities 59,091  (961,386)
Cash Flows from Discontinued Operations 1
Operating activities (1,202) 74,361 
Investing activities 4,494  1,985,202 
Financing activities —  (4,914)
Net cash provided by discontinued operations 3,292  2,054,649 
Cash transferred from discontinued operations to continuing operations —  2,083,565 
Effect of exchange rate changes on cash and cash equivalents (585) 2,593 
Net increase (decrease) in cash and cash equivalents (87,124) 74,976 
Cash and cash equivalents at beginning of period 306,760  359,923 
Cash and cash equivalents at end of period $ 219,636  434,899 
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)
2020 2019 2020 2019
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, 2020 and 195,083,364 shares at September 30, 2019
Balance at beginning of period 195,101  195,083  195,089  195,077 
Exercise of stock options —  —  12  6 
Balance at end of period 195,101  195,083  195,101  195,083 
Capital in Excess of Par Value
Balance at beginning of period 931,429  933,944  949,445  979,642 
Exercise of stock options, including income tax benefits —  —  (156) (123)
Restricted stock transactions and other (409) —  (33,649) (38,732)
Share-based compensation 5,298  7,365  20,678  25,041 
Adjustments to acquisition valuation —  —  —  (24,519)
Balance at end of period 936,318  941,309  936,318  941,309 
Retained Earnings
Balance at beginning of period 5,823,426  5,677,248  6,614,304  5,513,529 
Net (loss) income for the period (243,553) 1,089,002  (976,841) 1,221,456 
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact —  —  —  116,768 
Cash dividends (19,200) (39,934) (76,790) (125,437)
Balance at end of period 5,560,673  6,726,316  5,560,673  6,726,316 
Accumulated Other Comprehensive Loss
Balance at beginning of period (690,341) (549,045) (574,161) (609,787)
Foreign currency translation (loss) gain, net of income taxes 28,323  (17,128) (39,520) 36,927 
Retirement and postretirement benefit plans, net of income taxes 3,726  2,761  (45,219) 8,277 
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes 297  585  905  1,756 
Balance at end of period (657,995) (562,827) (657,995) (562,827)
Treasury Stock
Balance at beginning of period (1,691,070) (1,517,217) (1,717,217) (1,249,162)
Purchase of treasury shares —  (106,014) —  (405,938)
Awarded restricted stock, net of forfeitures 409  —  26,556  31,869 
Balance at end of period – 41,502,003 shares of Common Stock in 2020 and 37,853,330 shares of Common Stock in 2019, at cost
(1,690,661) (1,623,231) (1,690,661) (1,623,231)
Murphy Shareholders’ Equity 4,343,436  5,676,650  4,343,436  5,676,650 
Noncontrolling Interest
Balance at beginning of period 204,937  358,532  337,151  368,343 
Acquisition closing adjustments —  (3,328) —  (7,920)
Net (loss) income attributable to noncontrolling interest (23,055) 22,700  (122,869) 86,257 
Distributions to noncontrolling interest owners (11,273) (28,734) (43,673) (97,510)
Balance at end of period 170,609  349,170  170,609  349,170 
Total Equity $ 4,514,045  6,025,820  4,514,045  6,025,820 
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/the Company) on pages 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.
In connection with the LLOG acquisition, further discussed in Note P – Acquisitions, we hold a 0.5% interest in 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, 2020, our maximum exposure to loss was $3.5 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2020 and December 31, 2019, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2020 and 2019, in conformity with accounting principles generally accepted in the United States of America (U.S.).  In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities.  Actual results may differ from the estimates.
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2019 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, 2020 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Fair Value Measurement.  In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement.  The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019.  Implementation on a prospective or retrospective basis varies by specific disclosure requirement.  Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
Income Taxes.  In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU.  Early adoption is permitted. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.
Compensation-Retirement Benefits-Defined Benefit Plans-General.  In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.  For public companies, the amendments in this ASU are effective for fiscal years ending after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada.  Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.
U.S. - In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.  Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada - In Canada, contracts are primarily long-term floating commodity index priced, except for certain 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, 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. For the three-month and nine-month periods ended September 30, 2019, the Company recognized $750.3 million and $2,060.1 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) 2020 2019 2020 2019
Net crude oil and condensate revenue
United States
Onshore $ 86,498  219,515  272,284  547,756 
                      Offshore 216,918  398,518  714,143  1,090,462 
Canada    
Onshore 32,358  31,758  67,268  88,730 
Offshore 19,173  28,407  54,864  115,686 
Other
—  1,933  1,806  7,908 
Total crude oil and condensate revenue
354,947  680,131  1,110,365  1,850,542 
Net natural gas liquids revenue
United States
Onshore 6,766  5,557  16,145  22,497 
 
Offshore 4,765  8,414  13,255  18,184 
Canada
Onshore 2,780  2,751  6,090  8,987 
Total natural gas liquids revenue
14,311  16,722  35,490  49,668 
Net natural gas revenue
United States
Onshore 4,529  5,848  14,177  20,762 
Offshore 9,827  15,879  35,487  29,575 
Canada   
Onshore 41,710  31,757  116,108  109,580 
Total natural gas revenue
56,066  53,484  165,772  159,917 
Total revenue from contracts with customers 425,324  750,337  1,311,627  2,060,127 
(Loss) gain on crude contracts (5,290) 63,247  319,502  121,163 
Gain on sale of assets and other income 1,831  3,493  6,006  10,283 
Total revenue and other income $ 421,865  817,077  1,637,135  2,191,573 
Contract Balances and Asset Recognition
As of September 30, 2020, and December 31, 2019, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $70.8 million and $186.8 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13 (see Note B), the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any upstream oil and gas sale contracts that have financing components as of September 30, 2020.
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 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, 2020, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:
໿
Current Long-Term Contracts Outstanding at September 30, 2020
Approximate Volumes
Location Commodity End Date Description
U.S. Oil Q4 2021 Fixed quantity delivery in Eagle Ford 17,000 BOED
U.S. Natural Gas and NGL Q1 2023 Deliveries from dedicated acreage in Eagle Ford As produced
Canada Natural Gas Q4 2020 Contracts to sell natural gas at Alberta AECO fixed prices 59 MMCFD
Canada Natural Gas Q4 2020 Contracts to sell natural gas at USD Index pricing 60 MMCFD
Canada Natural Gas Q4 2021 Contracts to sell natural gas at USD Index pricing 10 MMCFD
Canada Natural Gas Q4 2022 Contracts to sell natural gas at Malin USD fixed prices 20 MMCFD
Canada Natural Gas Q4 2022 Contracts to sell natural gas at USD Index pricing 35 MMCFD
Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD Index pricing 30 MMCFD
Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD Index pricing 49 MMCFD
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant, and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
At September 30, 2020, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $187.9 million.  The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2020 and 2019.
(Thousands of dollars) 2020 2019
Beginning balance at January 1 $ 217,326  207,855 
Additions pending the determination of proved reserves 9,941  86,025 
Capitalized exploratory well costs charged to expense (39,408) (13,145)
Balance at September 30 $ 187,859  280,735 
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below). The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)

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,
2020 2019
(Thousands of dollars) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects
Aging of capitalized well costs:
Zero to one year $ 8,000  1  —  64,711  5  5 
One to two years 54,334  5  5  63,615  1  1 
Two to three years —  —  —  27,500  1  — 
Three years or more 125,525  6  —  124,909  5  — 
$ 187,859  12  5  280,735  12  6 
Of the $179.9 million of exploratory well costs capitalized more than one year at September 30, 2020, $88.2 million is in Vietnam, $46.0 million is in the U.S., $25.3 million is in Brunei, $15.6 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
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 38) 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, 2020.
Nine Months Ended
(Thousands of dollars) September 30, 2020
U.S. $ 1,152,515 
Other Foreign 39,709 
Corporate 14,060 
$ 1,206,284 
Divestments
In July 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $960.0 million was recorded as part of discontinued operations on the Consolidated Statement of Operations during 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy was entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020, however the results were not achieved by PTTEP.





11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)


Note E – Discontinued Operations and Assets Held for Sale
The Company has accounted for its former Malaysian exploration and production operations and its former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2020 and 2019 were as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
(Thousands of dollars) 2020 2019 2020 2019
Revenues $ —  972,737  4,074  1,328,110 
Costs and expenses
Lease operating expenses —  6,262  —  127,138 
Depreciation, depletion and amortization —  (1) —  33,697 
Other costs and expenses 778  11,079  10,981  81,560 
(Loss) income before taxes (778) 955,397  (6,907) 1,085,715 
Income tax expense —  2,029  —  58,083 
(Loss) income from discontinued operations $ (778) 953,368  (6,907) 1,027,632 
The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production operations, the U.K. refining and marketing operations and the Company’s office building in El Dorado, Arkansas and two airplanes that are reflected as held for sale on the Company’s Consolidated Balance Sheets. Subsequent to period end, one of the planes has been sold.
(Thousands of dollars) September 30,
2020 		December 31,
2019
Current assets
Cash $ 29,420  25,185 
Accounts receivable 425  4,834 
Inventories 406  406 
Prepaid expenses and other 831  1,882 
Property, plant, and equipment, net 68,393  82,116 
Deferred income taxes and other assets 9,441  9,441 
Total current assets associated with assets held for sale $ 108,916  123,864 
Current liabilities
Accounts payable $ 5,481  3,702 
Current maturities of long-term debt (finance lease) 728  705 
Taxes payable 1,510  1,411 
Long-term debt (finance lease) 6,702  7,240 
Asset retirement obligation 256  240 
Total current liabilities associated with assets held for sale $ 14,677  13,298 

Note F – Financing Arrangements and Debt
As of September 30, 2020, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At September 30, 2020, the Company had $200.0 million outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2020, the interest rate in effect on borrowings under the facility was 1.84%. At September 30, 2020, the Company was in compliance with all covenants related to the RCF.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2021.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.໿
Nine Months Ended
September 30,
(Thousands of dollars) 2020 2019
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹ $ 251,706  (128,698)
Decrease in inventories 4,747  4,398 
(Increase) in prepaid expenses (17,400) (3,745)
Increase (decrease) in accounts payable and accrued liabilities ¹ (264,078) 165,224 
Increase (decrease) in income taxes payable (1,236) 3,078 
Net (increase) decrease in noncash operating working capital $ (26,261) 40,257 
Supplementary disclosures:
Cash income taxes paid, net of refunds $ (12,559) (4,563)
Interest paid, net of amounts capitalized of $5.9 million in 2020 and $0.2 million in 2019
139,651  137,116 
Non-cash investing activities:
Asset retirement costs capitalized ² $ 6,342  48,203 
(Increase) decrease in capital expenditure accrual 74,742  (52,659)
1 Excludes receivable/payable balances relating to mark-to-market of crude contracts and contingent consideration relating to acquisitions.
2 2019 includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million. See Note P.

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.
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $63.0 million due to a lower discount rate and lower plan assets compared to December 31, 2019.
The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2020 and 2019.
Three Months Ended September 30,
Pension Benefits Other Postretirement Benefits
(Thousands of dollars) 2020 2019 2020 2019
Service cost $ 1,664  2,064  342  421 
Interest cost 4,827  7,151  612  945 
Expected return on plan assets (5,773) (6,455) —  — 
Amortization of prior service cost (credit) 149  248  —  (98)
Recognized actuarial loss 5,690  3,516  (24) — 
Net periodic benefit expense $ 6,557  6,524  930  1,268 
Nine Months Ended September 30,
Pension Benefits Other Postretirement Benefits
(Thousands of dollars) 2020 2019 2020 2019
Service cost $ 5,996  6,188  1,235  1,261 
Interest cost 16,381  21,402  2,200  2,833 
Expected return on plan assets (18,414) (19,285) —  — 
Amortization of prior service cost (credit) 515  741  —  (293)
Recognized actuarial loss 14,223  10,538  (24) — 
Net periodic benefit expense 18,701  19,584  3,411  3,801 
Other - curtailment 586  —  (1,825) — 
Other - special termination benefits 8,435  —  —  — 
Total net periodic benefit expense $ 27,722  19,584  1,586  3,801 
The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations. The curtailment and special termination benefits components are included in the line item “Restructuring expenses” in Consolidated Statement of Operations.
During the nine-month period ended September 30, 2020, the Company made contributions of $27.4 million to its defined benefit pension and postretirement benefit plans.  Remaining funding in 2020 for the Company’s defined benefit pension and postretirement plans is anticipated to be $10.3 million.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The 2017 Annual Incentive Plan (2017 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees.  Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. 
In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.
The 2020 Long-Term Plan and the 2018 Long-Term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2020 Long-Term Plan expires in 2030.  A total of 5,000,000 shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.
The Stock Plan for Non-Employee Directors (2018 NED Plan) permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
During the first nine months of 2020, the Committee granted 999,700 performance-based RSUs and 340,600 time-based RSUs to certain employees under the 2018 Long-Term Plan.  The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $21.51 per unit.  The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $21.68 per unit.  Additionally, in February 2020, the Committee granted 1,152,500 cash-settled RSUs (CRSU) to certain employees.  The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards.  The initial fair value of the CRSUs granted in February 2020 was $21.68.  Also, in February, the Committee granted 106,248 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 NED Plan.  These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $22.59 per unit on date of grant.
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, 2020.
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) 2020 2019
Compensation charged against income before tax benefit $ 17,542  39,884 
Related income tax benefit recognized in income 2,278  6,204 
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
15
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, 2020 and 2019.  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) 2020 2019 2020 2019
Basic method 153,596,109  160,365,705  153,479,654  167,310,202 
Dilutive stock options and restricted stock units ¹ —  614,333  —  795,025 
Diluted method 153,596,109  160,980,038  153,479,654  168,105,227 
1 Due to a net loss recognized by the Company for 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,
2020 2019 2020 2019
Antidilutive stock options excluded from diluted shares 2,111,068  2,903,768  2,305,973  3,016,361 
Weighted average price of these options $ 38.54  $ 44.65  $ 40.15  $ 45.38 

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes.  For the three-month and nine-month periods ended September 30, 2020 and 2019, the Company’s effective income tax rates were as follows:
2020 2019
Three months ended September 30, 19.1% 10.6%
Nine months ended September 30, 18.6% 12.1%
The effective tax rate for the three-month period ended September 30, 2020 was below the U.S. statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM.
The effective tax rate for the three-month period ended September 30, 2019 was below the U.S. statutory tax rate of 21% due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million.
The effective tax rate for the nine-month period ended September 30, 2020 was below the U.S. statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.
The effective tax rate for the nine-month period ended September 30, 2019 was below the statutory tax rate of 21% due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million, a reduction of the Alberta provincial corporate income tax rate that reduced the future deferred tax liability by $13 million, and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take multiple years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of September 30, 2020, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; Malaysia – 2013; and United Kingdom – 2018. Following the divestment of Malaysia in the
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K– Income Taxes (Contd.)

third quarter of 2019, the Company has retained certain possible tax and other liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss until the anticipated transactions occur.
Commodity Price Risks
At September 30, 2020, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing through December 2020 at an average price of $56.42, and 18,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2021 at an average price of $43.31. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.
At September 30, 2019, the Company had 35,000 barrels per day in WTI crude oil swap financial contracts maturing through December 2019 at an average price of $60.51 and 35,000 barrels per day in WTI crude oil swap financial contracts maturing through December 2020 at an average price of $57.59.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at September 30, 2020 and 2019.
At September 30, 2020 and December 31, 2019, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
September 30, 2020 December 31, 2019
(Thousands of dollars) Asset (Liability) Derivatives Asset (Liability) Derivatives
Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value
Commodity Accounts receivable $ 93,774  Accounts payable $ (33,364)
For the three-month and nine-month periods ended September 30, 2020 and 2019, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
Gain (Loss) Gain (Loss)
(Thousands of dollars) Statement of Operations Location Three Months Ended September 30, Nine months ended September 30,
Type of Derivative Contract 2020 2019 2020 2019
Commodity (Loss) gain on crude contracts $ (5,290) 63,247  $ 319,502  121,163 
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During the nine-month periods ended September 30, 2020 and 2019, $1.1 million and $2.2 million, respectively, of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations.  The remaining loss (net of tax) deferred on these matured contracts at September 30, 2020 was $2.0 million and is recorded, net of income taxes of $0.5 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.4 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2020.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2020 and December 31, 2019, are presented in the following table.
September 30, 2020 December 31, 2019
(Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets:
Commodity derivative contracts $ —  93,774  —  93,774  —  —  —  — 
$ —  93,774  —  93,774  —  —  —  — 
Liabilities:
Commodity derivative contracts $ —  —  —  —  —  33,364  —  33,364 
Nonqualified employee savings plans 16,169  —  —  16,169  17,035  —  —  17,035 
Contingent consideration —  —  117,311  117,311  —  —  146,787  146,787 
$ 16,169  —  117,311  133,480  17,035  33,364  146,787  197,186 
The fair value of WTI crude oil derivative contracts in 2020 and 2019 were based on active market quotes for WTI crude oil.  The income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations. 
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations. 
The contingent consideration, related to two acquisitions in 2019 and 2018, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other (benefit) expense in the Consolidated Statements of Operations. Any remaining contingent consideration payable will be due annually in years 2021 to 2026.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at September 30, 2020 and December 31, 2019.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2019 and September 30, 2020 and the changes during the nine-month period ended September 30, 2020, are presented net of taxes in the following table.
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note M – Accumulated Other Comprehensive Loss (Contd.)
(Thousands of dollars) Foreign
Currency
Translation
Gains (Losses) 		Retirement
and
Postretirement
Benefit Plan
Adjustments 		Deferred
Loss on
Interest Rate
Derivative
Hedges 		Total
Balance at December 31, 2019 $ (353,252) (218,015) (2,894) (574,161)
Components of other comprehensive income (loss):
Before reclassifications to income and retained earnings (39,520) (55,707) —  (95,227)
Reclassifications to income —  10,488  ¹ 905  ² 11,393 
Net other comprehensive income (loss) (39,520) (45,219) 905  (83,834)
Balance at September 30, 2020 $ (392,772) (263,234) (1,989) (657,995)

1 Reclassifications before taxes of $13,720 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2020.  See Note H for additional information.  Related income taxes of $3,232 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2020.
2 Reclassifications before taxes of $1,147 are included in Interest expense, net, for the nine-month period ended September 30, 2020.  Related income taxes of $242 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2020.  See Note L for additional information.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been, and may be, affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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 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.
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment.  Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled.  Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous 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 remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.  
The Company has retained certain liabilities related to environmental and operational matters at formerly owned U.S. refineries that were sold in 2011.  The Company obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income/(loss), financial condition or liquidity in a future period.
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred, at known or currently unidentified sites, is not expected to have a material adverse effect on the Company’s future net income/(loss), cash flows or liquidity.
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income/ (loss), financial condition or liquidity in a future period.
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – Business Segments
Information about business segments and geographic operations is reported in the following table.  For geographic purposes, revenues are attributed to the country in which the sale occurs.  Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.໿
Total Assets at September 30, 2020 Three Months Ended September 30, 2020 Three Months Ended September 30, 2019
(Millions of dollars) External
Revenues 		Income
(Loss) 		External
Revenues 		Income
(Loss)
Exploration and production ¹
United States $ 7,028.0  330.8  (172.6) 656.8  170.8 
Canada 2,155.5  96.3  (8.6) 95.0  (9.1)
Other 264.1  —  (11.7) 1.9  (3.7)
Total exploration and production 9,447.6  427.1  (192.9) 753.7  158.0 
Corporate 1,002.1  (5.2) (72.9) 63.4  0.3 
Assets/revenue/income (loss) from continuing operations 10,449.7  421.9  (265.8) 817.1  158.3 
Discontinued operations, net of tax 19.7  —  (0.8) —  953.4 
Total $ 10,469.4  421.9  (266.6) 817.1  1,111.7 
Nine Months Ended September 30, 2020 Nine Months Ended September 30, 2019
External
Revenues 		Income
(Loss) 		External
Revenues 		Income
(Loss)
Exploration and production ¹
United States $ 1,070.6  (1,011.7) 1,734.3  420.0 
Canada 245.2  (35.0) 323.8  (7.5)
Other 1.8  (73.0) 7.9  (35.4)
Total exploration and production 1,317.6  (1,119.7) 2,066.0  377.1 
Corporate 319.5  26.9  125.6  (97.0)
Assets/revenue/income (loss) from continuing operations 1,637.1  (1,092.8) 2,191.6  280.1 
Discontinued operations, net of tax —  (6.9) —  1,027.6 
Total $ 1,637.1  (1,099.7) 2,191.6  1,307.7 
1 Additional details about results of oil and gas operations are presented in the table on pages 26 and 27.
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Acquisitions
LLOG Acquisition:
In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.

Note Q – Restructuring Charges

On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income during the three and nine months ended September 30, 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, one of the planes has been sold. All Restructuring charges have been recorded in the Corporate segment.

The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the three and nine months ended September 30, 2020:
(Thousands of dollars) Three Months Ended
September 30, 2020 		Nine Months Ended
September 30, 2020
Severance $ 2,635  22,502 
Pension and termination benefit charges —  10,913 
Contract exit costs and other 2,347  12,964 
Restructuring charges $ 4,982  46,379 

The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at September 30, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:
(Thousands of dollars)
Restructuring accruals $ 28,814 
Utilizations (19,635)
Liability at September 30, 2020 $ 9,179 
22
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In 2020 the continued spread of coronavirus disease 2019 (COVID-19) has led to disruption in the global economy and a weakness in demand for crude oil. In the first quarter of 2020, certain major global suppliers of crude oil announced supply increases which resulted in a contribution to the lower global commodity prices in the first quarter and early second quarter. In early second quarter of 2020, the OPEC+ group of oil producing countries agreed to supply restrictions which helped support the oil price in the latter part of the second quarter and during the third quarter. Nevertheless, oil prices during the third quarter 2020 remained below average 2019 prices. The reduction in commodity prices compared to 2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 35.
For the three months ended September 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $41 per barrel (compared to $28 in the second quarter of 2020 and $56 in the third quarter of 2019). The closing price for WTI at the end of the third quarter of 2020 was approximately $40 per barrel, reflecting a 34% reduction from the price at the end of 2019. The average price in October 2020 was $39.55 per barrel. As of close on November 4, 2020, the NYMEX WTI forward curve prices for the remainder of 2020 and 2021 were $39.15 and $41.06 per barrel, respectively.
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 Floating Production System (FPS). The Company reported net loss from continuing operations of $265.8 million (which includes a loss attributable to noncontrolling interest of $23.1 million) for the third quarter of 2020.
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 (which includes impairment charges of $854.2 million, net of tax, and a loss attributable to noncontrolling interest of $122.9 million) for the nine months ended September 30, 2020.
For the three months ended September 30, 2019, the Company produced 203 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $356.6 million in capital expenditures (on a value of work done basis) in the third quarter of 2019. The Company reported net income from continuing operations of $158.3 million (which includes income attributable to noncontrolling interest of $22.7 million) for the three months ended September 30, 2019.
For the nine months ended September 30, 2019, the Company produced 179 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $2.3 billion in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $280.1 million (which includes income attributable to noncontrolling interest of $86.3 million) for the nine months ended September 30, 2019.
During the three-month and nine-month periods ended September 30, 2020, crude oil and condensate volumes from continuing operations were lower than the prior year period as a result of lower Eagle Ford Shale volumes (due to lower capital expenditures) and higher hurricane and storm downtime in the Gulf of Mexico. Revenue, compared to 2019, was also impacted by the lower average oil prices. The results are explained in more detail below.
23
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

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) 2020 2019 2020 2019
Exploration and production $ (192.9) 158.0  (1,119.7) 377.1 
Corporate and other (72.9) 0.3  26.9  (97.0)
(Loss) income from continuing operations (265.8) 158.3  (1,092.8) 280.1 
Discontinued operations ¹ (0.8) 953.4  (6.9) 1,027.6 
Net (loss) income including noncontrolling interest $ (266.6) 1,111.7  (1,099.7) 1,307.7 
1 The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
Income (Loss)
Three Months Ended
September 30, 		Nine Months Ended September 30,
(Millions of dollars) 2020 2019 2020 2019
Exploration and production
United States $ (172.6) 170.8  (1,011.7) 420.0 
Canada (8.6) (9.1) (35.0) (7.5)
Other (11.7) (3.7) (73.0) (35.4)
Total $ (192.9) 158.0  (1,119.7) 377.1 

























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

Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net (loss) income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
(Millions of dollars, except per barrel of oil equivalents sold)
2020 2019 2020 2019
Net (loss) income attributable to Murphy (GAAP) $ (243.6) 1,089.0  (976.8) 1,221.5 
Income tax (benefit) expense (62.6) 18.8  (248.9) 38.7 
Interest expense, net 45.2  44.9  124.9  145.1 
Depreciation, depletion and amortization expense ¹ 219.7  308.3  725.1  766.4 
EBITDA attributable to Murphy (Non-GAAP) (41.3) 1,461.0  (375.7) 2,171.7 
Impairment of assets ¹ 186.5  —  1,072.5  — 
Mark-to-market loss (gain) on crude oil derivative contracts 69.3  (49.2) (104.5) (100.1)
Mark-to-market loss (gain) on contingent consideration 14.0  (28.4) (29.5) 0.5 
Restructuring expenses 5.0  —  46.4  — 
Accretion of asset retirement obligations 10.8  10.6  31.2  29.8 
Unutilized rig charges 5.2  —  13.2  — 
Discontinued operations loss (income) 0.8  (953.4) 6.9  (1,027.6)
Inventory loss —  —  4.8  — 
Foreign exchange losses (gains) 0.8  0.8  (2.5) 6.4 
Business development transaction costs —  4.1  —  24.4 
Write-off of previously suspended exploration wells —  —  —  13.2 
Seal insurance proceeds (1.7) (8.0) (1.7) (8.0)
Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 249.4  437.5  661.1  1,110.3 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 14,166  17,745  46,478  45,511 
Adjusted EBITDA per barrel of oil equivalents sold $ 17.61  24.65  14.22  24.40 
1 Depreciation, depletion, and amortization expense used in the computation of EBITDA and impairment of assets used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.

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

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2020 AND 2019
(Millions of dollars)
United
States 1
Canada Other Total
Three Months Ended September 30, 2020
Oil and gas sales and other operating revenues $ 330.8  96.3  —  427.1 
Lease operating expenses 91.5  32.6  0.4  124.5 
Severance and ad valorem taxes 6.4  0.3  —  6.7 
Transportation, gathering and processing 29.3  12.0  —  41.3 
Depreciation, depletion and amortization 166.2  59.6  0.5  226.3 
Impairments of assets 205.1  —  —  205.1 
Accretion of asset retirement obligations 9.4  1.4  —  10.8 
Exploration expenses
Dry holes and previously suspended exploration costs 0.6  —  —  0.6 
Geological and geophysical 0.1  —  (0.1) — 
Other exploration 0.6  0.1  3.6  4.3 
1.3  0.1  3.5  4.9 
Undeveloped lease amortization 4.9  0.1  2.3  7.3 
Total exploration expenses 6.2  0.2  5.8  12.2 
Selling and general expenses 5.3  3.4  1.6  10.3 
Other 22.5  (1.5) 2.5  23.5 
Results of operations before taxes (211.1) (11.7) (10.8) (233.6)
Income tax provisions (benefits) (38.5) (3.1) 0.9  (40.7)
Results of operations (excluding Corporate segment) $ (172.6) (8.6) (11.7) (192.9)

Three Months Ended September 30, 2019
Oil and gas sales and other operating revenues $ 656.8  95.0  1.9  753.7 
Lease operating expenses 116.2  31.2  0.2  147.6 
Severance and ad valorem taxes 13.4  0.4  —  13.8 
Transportation, gathering and processing 44.1  10.2  —  54.3 
Depreciation, depletion and amortization 253.5  65.3  0.6  319.4 
Accretion of asset retirement obligations 9.0  1.6  —  10.6 
Exploration expenses
Dry holes and previously suspended exploration costs (0.1) —  —  (0.1)
Geological and geophysical 0.2  —  0.2  0.4 
Other exploration 1.5  0.1  3.8  5.4 
1.6  0.1  4.0  5.7 
Undeveloped lease amortization 5.2  0.3  1.0  6.5 
Total exploration expenses 6.8  0.4  5.0  12.2 
Selling and general expenses 22.7  7.6  5.6  35.9 
Other (21.0) (7.3) 0.5  (27.8)
Results of operations before taxes 212.1  (14.4) (10.0) 187.7 
Income tax provisions (benefits) 41.3  (5.3) (6.3) 29.7 
Results of operations (excluding Corporate segment) $ 170.8  (9.1) (3.7) 158.0 
1 Includes results attributable to a noncontrolling interest in MP GOM.

26
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2020 AND 2019
(Millions of dollars)
United
States 1
Canada Other Total
Nine Months Ended September 30, 2020
Oil and gas sales and other operating revenues $ 1,070.6  245.2  1.8  1,317.6 
Lease operating expenses 386.5  90.6  1.2  478.3 
Severance and ad valorem taxes 21.6  1.0  —  22.6 
Transportation, gathering and processing 95.4  31.4  —  126.8 
Depreciation, depletion and amortization 589.5  161.3  1.5  752.3 
Impairment of assets 1,152.5  —  39.7  1,192.2 
Accretion of asset retirement obligations 27.1  4.1  —  31.2 
Exploration expenses
Dry holes and previously suspended exploration costs 8.3  —  —  8.3 
Geological and geophysical 9.4  0.1  4.1  13.6 
Other exploration 4.3  0.4  13.1  17.8 
22.0  0.5  17.2  39.7 
Undeveloped lease amortization 14.8  0.3  6.9  22.0 
Total exploration expenses 36.8  0.8  24.1  61.7 
Selling and general expenses 16.6  13.2  5.5  35.3 
Other 1.0  (2.5) 1.4  (0.1)
Results of operations before taxes (1,256.4) (54.7) (71.6) (1,382.7)
Income tax provisions (benefits) (244.7) (19.7) 1.4  (263.0)
Results of operations (excluding Corporate segment) $ (1,011.7) (35.0) (73.0) (1,119.7)
Nine months ended September 30, 2019
Oil and gas sales and other operating revenues $ 1,734.3  323.8  7.9  2,066.0 
Lease operating expenses 308.3  107.1  1.1  416.5 
Severance and ad valorem taxes 36.0  1.0  —  37.0 
Transportation, gathering and processing 103.4  25.3  —  128.7 
Depreciation, depletion and amortization 618.6  181.6  2.9  803.1 
Accretion of asset retirement obligations 25.2  4.6  —  29.8 
Exploration expenses
Dry holes and previously suspended exploration costs (0.2) —  13.1  12.9 
Geological and geophysical 16.1  —  8.1  24.2 
Other exploration 5.5  0.3  10.9  16.7 
21.4  0.3  32.1  53.8 
Undeveloped lease amortization 18.0  1.0  2.7  21.7 
Total exploration expenses 39.4  1.3  34.8  75.5 
Selling and general expenses 52.9  21.3  17.3  91.5 
Other 37.5  (6.9) 0.9  31.5 
Results of operations before taxes 513.0  (11.5) (49.1) 452.4 
Income tax provisions (benefits) 93.0  (4.0) (13.7) 75.3 
Results of operations (excluding Corporate segment) $ 420.0  (7.5) (35.4) 377.1 
1 Includes results attributable to a noncontrolling interest in MP GOM.
27
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Exploration and Production
Third quarter 2020 vs. 2019
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported a loss of $172.6 million in the third quarter of 2020 compared to income of $170.8 million in the third quarter of 2019.  Results were $343.4 million unfavorable in the 2020 quarter compared to the 2019 period due to lower revenues ($326.0 million) and higher impairment charges ($205.1 million), partially offset by lower depreciation, depletion and amortization ($87.3 million), income tax expense ($79.8 million), lease operating expenses ($24.7 million), general and administrative (G&A: $17.4 million), and transportation, gathering, and processing expenses ($14.8 million). Lower revenues were primarily due to lower commodity prices, lower Eagle Ford Shale volumes (due to lower capital expenditures), and lower volumes in the U.S. Gulf of Mexico (as a result of shut-ins due to hurricane activity in the 2020 quarter). The impairment charge in the quarter relates to the Gulf of Mexico Cascade & Chinook field which, primarily as a result of lower commodity prices and lower capital expenditure plans, was written down to its expected future value. Lower depreciation expense was primarily due to lower depreciation rates following the impairment charges incurred in the first quarter of 2020 and lower sales volume. Lower lease operating expense was primarily attributable to wells being shut-in in the Gulf of Mexico and certain cost-savings initiatives taken across all businesses. Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).
Canadian E&P operations reported a loss of $8.6 million in the third quarter 2020 compared to a loss of $9.1 million in the 2019 quarter.  Results were favorable $0.5 million compared to the 2019 period primarily due to higher revenue ($1.3 million), lower depreciation and amortization ($5.7 million), higher tax benefit ($2.2 million), partially offset by lower other operating income ($5.8 million), higher transportation, gathering, and processing expenses ($1.8 million), and higher lease operating expenses ($1.4 million).  Higher revenue is primarily attributable to higher gas prices at Tupper, Kaybob, and Placid (higher AECO prices in the quarter). Lower depreciation expense is due to lower production volumes at Tupper and Terra-Nova (shut-in starting in December 2019). Terra Nova is expected to be shut-in for the remainder of 2020 for Asset Integrity work.
Other international E&P operations reported a loss from continuing operations of $11.7 million in the third quarter of 2020 compared to a net a loss of $3.7 million in the prior year quarter. The result was $8.0 million unfavorable in the 2020 period versus 2019 primarily due higher prior period revenue in Brunei and a prior year income tax credit related to Vietnam exploration spend.
Nine months 2020 vs.2019
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported a loss of $1,011.7 million in the first nine months of 2020 compared to income of $420 million in the first nine months of 2019.  Results were $1,431.7 million unfavorable in the 2020 period compared to the 2019 period primarily due to an impairment charge ($1,152.5 million), lower revenues ($663.7 million), higher lease operating expenses ($78.2 million), partially offset by lower income tax expense ($337.7 million), other operating expense ($36.5 million), G&A ($36.3 million), depreciation, depletion and amortization (DD&A: $29.1 million), and transportation, gathering, and processing charges ($8.0 million). The impairment charge is primarily the result of lower forecast future prices, as a result of decreased oil demand and increased oil supply (as discussed above). Based on an evaluation of expected future cash flows from properties as of September 30, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recorded in the future. Lower revenues were primarily due to lower commodity prices year over year and lower volumes in the U.S. Gulf of Mexico (as a result of shut-ins related to hurricanes and storms). Higher lease operating expenses were due primarily to well workovers at Cascade ($51.3 million) and Dalmatian ($20.5 million). Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration (as a result of lower commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($29.5 million). Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).
Canadian E&P operations reported a loss of $35.0 million in the first nine months of 2020 compared to a loss of $7.5 million in the first nine months of 2019.  Results were unfavorable $27.5 million compared to the 2019 period primarily due to lower revenue ($78.6 million), partially offset by lower lease operating expense ($16.5 million), lower DD&A ($20.3 million), and lower income tax charges ($15.7 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue through 2020 full year). Lower lease operating expenses and lower DD&A were a result of lower sales.
28
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Other international E&P operations reported a loss from continuing operations of $73 million in the first nine months of 2020 compared to a net loss of $35.4 million in the prior year.  The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.

Corporate
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income. These costs include severance, relocation, IT costs, pension curtailment, termination charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, one of the planes has been sold.
Third quarter 2020 vs. 2019
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $72.9 million in the third quarter 2020 compared to net income of $0.3 million in the 2019 quarter. The $73.2 million unfavorable variance is principally due to 2020 mark to market losses on forward swap commodity contracts ($69.4 million) compared to gains on forward contracts ($49.2 million) in the third quarter of 2019, impairment of the El Dorado office building ($14.1 million), and restructuring charges ($5.0 million), partially offset by higher realized gains on forward commodity contracts ($50.1 million) and a higher tax credit ($10.9 million). Losses on forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with a fixed price. Higher realized gains on forward commodity contracts are due to lower prices versus the fixed contract price.
Nine months 2020 vs. 2019
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported earnings of $26.9 million in the first nine months of 2020 compared to a loss of $97.0 million in the first nine months of 2019. The $123.9 million favorable variance is primarily due to higher realized gains on forward swap commodity contracts ($194.0 million), lower interest charges ($20.6 million), lower G&A ($15.7 million), and partially offset by higher tax charges ($50.7 million) and restructuring charges ($46.4 million) related to the closure of the El Dorado and Calgary offices. Higher realized gains on forward swap commodity contracts are due to lower market pricing whereby the contract provides the Company with a fixed price. Interest charges are lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020. As of September 30, 2020, the average forward NYMEX WTI price for the remainder of 2020 was $40.35 and for 2021 was $42.21 (versus fixed hedge prices of $56.42 and $43.31; see below).

29
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

Production Volumes and Prices
Third quarter 2020 vs. 2019
Total hydrocarbon production from continuing operations averaged 162,824 barrels of oil equivalent per day in the third quarter of 2020, which represented a 20% decrease from the 203,035 barrels per day produced in third quarter 2019. The decrease was principally due to GOM shut-in production due to hurricanes (14.2 MBOED) and lower Eagle Ford Shale production (16.2 MBOED, as a result of lower capex spend at this property).
Average crude oil and condensate production from continuing operations was 95,391 barrels per day in the third quarter of 2020 compared to 122,950 barrels per day in the third quarter of 2019. The decrease of 27,559 barrels per day was principally due to lower Eagle Ford Shale production due to lower capital expenditures (15,731 barrels per day) and lower volumes in the Gulf of Mexico (14,066 barrels per day) due to GOM shut-in production due to hurricanes (11.1 MBOED). On a worldwide basis, the Company’s crude oil and condensate prices averaged $39.79 per barrel in the third quarter 2020 compared to $59.47 per barrel in the 2019 period, a decrease of 33% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 10,523 barrels per day in the third quarter 2020 compared to 13,601 barrels per day in the 2019 period.  The average sales price for U.S. NGL was $14.78 per barrel in the 2020 quarter compared to $13.26 per barrel in 2019. The average sales price for NGL in Canada was $19.97 per barrel in the 2020 quarter compared to $21.03 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 341 million cubic feet per day (MMCFD) in the third quarter 2020 compared to 399 MMCFD in 2019.  The decrease of 57 MMCFD was a result of lower volumes in the Gulf of Mexico (20 MMCFD) and lower volumes in Canada (36 MMCFD).  Lower volumes in the Gulf of Mexico are due to GOM shut-in production due to hurricanes. Lower volumes in Canada are due to normal well decline and no additional wells in third quarter of 2020.
Natural gas prices for the total Company averaged $1.78 per thousand cubic feet (MCF) in the 2020 quarter, versus $1.46 per MCF average in the same quarter of 2019.  Average natural gas prices in the US and Canada in the quarter were $1.94 and $1.74 respectively.
Nine months 2020 vs. 2019
Total hydrocarbon production from all E&P continuing operations averaged 180,443 barrels of oil equivalent per day in the first nine months of 2020, which represented a 1% increase from the 178,658 barrels per day produced in the first nine months of 2019. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
Average crude oil and condensate production from continuing operations was 108,678 barrels per day in the first nine months of 2020 compared to 110,762 barrels per day in the first nine months of 2019. The decrease of 2,084 barrels per day was principally due to lower Eagle Ford Shale production (5,311 barrels per day), offset by higher volumes in the Gulf of Mexico (3,111 barrels per day) due to the acquisition of assets as part of the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $36.88 per barrel in the first nine months of 2020 compared to $60.94 per barrel in the 2019 period, a decrease of 39% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 11,901 barrels per day in the first nine months of 2020 compared to 10,990 barrels per day in the 2019 period.  The average sales price for U.S. NGL was $10.13 per barrel in 2020 compared to $15.22 per barrel in 2019.  The average sales price for NGL in Canada was $16.95 per barrel in 2020 compared to $27.50 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 359 million cubic feet per day (MMCFD) in the first nine months of 2020 compared to 341 MMCFD in 2019.  The increase of 18 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (24 MMCFD).  Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the LLOG transaction.
Natural gas prices for the total Company averaged $1.68 per thousand cubic feet (MCF) in the first nine months of 2020, versus $1.72 per MCF average in the same period of 2019.  Average natural gas prices in the US and Canada in the quarter were $1.87 and $1.62, respectively.
Additional details about results of oil and gas operations are presented in the tables on pages 26 and 27.
30
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2020 and 2019.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
Barrels per day unless otherwise noted 2020 2019 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 24,851  40,582  27,945  33,256 
Gulf of Mexico 1
56,517  70,583  67,377  64,266 
Canada Onshore 9,595  7,101  8,106  6,503 
Offshore 4,428  4,333  5,136  6,302 
Other —  351  114  435 
Total net crude oil and condensate - continuing operations 95,391  122,950  108,678  110,762 
Net natural gas liquids
United States Onshore 5,489  5,582  5,459  5,621 
Gulf of Mexico 1
3,521  6,597  5,131  4,172 
Canada Onshore 1,513  1,422  1,311  1,197 
Total net natural gas liquids - continuing operations 10,523  13,601  11,901  10,990 
Net natural gas – thousands of cubic feet per day
United States Onshore 27,520  29,122  29,054  30,203 
Gulf of Mexico 1
53,046  72,897  67,850  44,029 
Canada Onshore 260,895  296,883  262,279  267,205 
Total net natural gas - continuing operations 341,461  398,902  359,183  341,437 
Total net hydrocarbons - continuing operations including NCI 2,3
162,824  203,035  180,443  178,658 
Noncontrolling interest
Net crude oil and condensate – barrels per day (9,298) (10,322) (10,674) (11,215)
Net natural gas liquids – barrels per day (327) (478) (443) (496)
Net natural gas – thousands of cubic feet per day (3,269) (3,403) (4,137) (3,933)
Total noncontrolling interest (10,170) (11,367) (11,807) (12,367)
Total net hydrocarbons - continuing operations excluding NCI 2,3
152,654  191,668  168,636  166,292 
Discontinued operations
Net crude oil and condensate – barrels per day —  1,748  —  16,331 
Net natural gas liquids – barrels per day —  37  —  434 
Net natural gas – thousands of cubic feet per day 2
—  9,624  —  67,863 
Total discontinued operations —  3,389  —  28,076 
Total net hydrocarbons produced excluding NCI 2,3
152,654  195,057  168,636  194,367 
1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains hydrocarbons sold during the three-month and nine-month periods ended September 30, 2020 and 2019.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
Barrels per day unless otherwise noted 2020 2019 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 24,851  40,582  27,945  33,256 
Gulf of Mexico 1
57,756  71,380  68,436  64,532 
Canada Onshore 9,595  7,101  8,106  6,503 
Offshore 4,757  4,945  5,290  6,523 
Other —  309  104  415 
Total net crude oil and condensate - continuing operations 96,959  124,317  109,881  111,229 
Net natural gas liquids
United States Onshore 5,489  5,582  5,459  5,622 
Gulf of Mexico 1
3,521  6,597  5,131  4,172 
Canada Onshore 1,513  1,422  1,311  1,197 
Total net natural gas liquids - continuing operations 10,523  13,601  11,901  10,991 
Net natural gas – thousands of cubic feet per day
United States Onshore 27,520  29,122  29,054  30,203 
Gulf of Mexico 1
53,046  72,897  67,850  44,029 
Canada Onshore 260,895  296,882  262,279  267,205 
Total net natural gas - continuing operations 341,461  398,901  359,183  341,437 
Total net hydrocarbons - continuing operations including NCI 2,3
164,392  204,402  181,646  179,126 
Noncontrolling interest
Net crude oil and condensate – barrels per day (9,545) (10,481) (10,886) (11,269)
Net natural gas liquids – barrels per day (327) (478) (443) (496)
Net natural gas – thousands of cubic feet per day 2
(3,269) (3,403) (4,137) (3,933)
Total noncontrolling interest (10,417) (11,526) (12,019) (12,421)
Total net hydrocarbons - continuing operations excluding NCI 2,3
153,975  192,875  169,627  166,706 
Discontinued operations
Net crude oil and condensate – barrels per day —  1,424  —  16,177 
Net natural gas liquids – barrels per day —  32  —  395 
Net natural gas – thousands of cubic feet per day 2
—  9,624  —  67,863 
Total discontinued operations —  3,060  —  27,883 
Total net hydrocarbons sold excluding NCI 2,3
153,975  195,935  169,627  194,588 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 2020 and 2019.໿ Comparative periods are conformed to current presentation.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2020 2019 2020 2019
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States Onshore $ 37.83  58.80  35.56  60.33 
Gulf of Mexico 1
40.82  60.69  38.08  61.90 
Canada 2
Onshore 36.65  48.61  30.29  49.98 
Offshore 43.81  62.44  37.85  64.97 
Other —  67.96  63.51  69.86 
Natural gas liquids – dollars per barrel
United States Onshore 13.39  10.82  10.78  14.66 
Gulf of Mexico 1
14.71  13.86  9.43  15.96 
Canada 2
Onshore 19.97  21.03  16.95  27.50 
Natural gas – dollars per thousand cubic feet
United States Onshore 1.78  2.18  1.76  2.51 
Gulf of Mexico 1
2.01  2.37  1.91  2.46 
Canada 2
Onshore 1.74  1.16  1.62  1.50 
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia 3
Sarawak —  —  —  70.39 
Block K —  69.24  —  65.75 
Natural gas liquids – dollars per barrel
Malaysia 3
Sarawak —  54.11  —  48.23 
Natural gas – dollars per thousand cubic feet
Malaysia 3
Sarawak —  3.69  —  3.60 
Block K —  0.23  —  0.24 
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3  Prices are net of payments under the terms of the respective production sharing contracts.

Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $578.0 million for the first nine months of 2020 compared to $1,153.2 million during the same period in 2019.  The decreased cash from operating activities is primarily attributable to lower revenue from sales to customers ($748.5 million) and higher lease operating expenses ($61.8 million), partially offset by higher cash payments received on forward swap commodity contracts ($194.0 million) and lower general and administrative expenses ($71.9 million). See above for explanation of underlying business reasons.
Cash Required by Investing Activities
Cash required by property additions and dry holes, which includes amounts expensed, were $723.7 million and $2,203.0 million in the nine-month periods ended September 30, 2020 and 2019, respectively.  In 2020, property additions include $74.9 million used to fund the development of the King’s Quay FPS which is expected to be refunded on the closing of a transaction to sell this asset to a third party. In 2019, property additions included the LLOG acquisition. Lower property additions in 2020 are a result of
33
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)

reducing the 2020 capital spending budget in response to the current commodity price environment. See Outlook section on page 35 for further details.
Total accrual basis capital expenditures were as follows:
Nine Months Ended
September 30,
(Millions of dollars) 2020 2019
Capital Expenditures
Exploration and production $ 671.0  2,320.6 
Corporate 9.3  8.5 
Total capital expenditures $ 680.3  2,329.1 
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) 2020 2019
Property additions and dry hole costs per cash flow statements $ 648.7  995.5 
Property additions King's Quay per cash flow statements 74.9  13.6 
Acquisition of oil and gas properties —  1,226.1 
Geophysical and other exploration expenses 26.8  36.6 
Capital expenditure accrual changes and other (70.2) 57.1 
Total capital expenditures $ 680.3  2,329.1 
Capital expenditures in the exploration and production business in 2020 compared to 2019 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, with significant capital expenditure reductions in the Eagle Ford Shale. The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party.
Cash Provided by Financing Activities
Net cash provided by financing activities was $59.1 million for the first nine months of 2020 compared to net cash required by financing activities of $961.4 million during the same period in 2019. In 2020, the cash provided by financing activities was principally from net borrowings on the Company’s unsecured RCF ($200.0 million at the end of the third quarter 2020). In 2019, the cash required by financing activities was principally from borrowings on our revolver and short-term loan ($1,575.0 million) to fund the LLOG acquisition. These borrowings, along with the opening revolver balance ($325.0 million) of $1,900.0 million were repaid in July 2019 following the completion of the Malaysia divestment. Total cash dividends to shareholders amounted to $76.8 million for the nine months ended September 30, 2020 compared to $125.4 million in the same period of 2019 due to a 50% reduction in the quarterly dividend effective in the second quarter 2020 and cash used for share repurchases of $405.9 million throughout 2019. As of September 30, 2020 and in the event it is required to fund investing or operating activities from borrowings, the Company has $1,396.3 million available on its committed RCF.
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2020 was $30.0 million, $109.1 million higher than December 31, 2019, with the increase primarily attributable to lower accounts payable $306.7 million and lower other accrued liabilities $39.9 million, partly offset by a lower cash balance ($87.1 million) and lower accounts receivable ($147.5 million). Lower accounts payable is due to lower capital activity. Lower accounts receivable is due to lower commodity sales prices.
Capital Employed
At September 30, 2020, long-term debt of $2,987.1 million had increased by $183.7 million compared to December 31, 2019, as a result of net borrowing on the RCF.  The fixed-rate notes had a weighted average maturity of 7.0 years and a weighted average coupon of 5.9 percent.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)

A summary of capital employed at September 30, 2020 and December 31, 2019 follows.
September 30, 2020 December 31, 2019
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 2,987.1  40.7  % $ 2,803.4  33.9  %
Murphy shareholders' equity 4,343.4  59.3  % 5,467.5  66.1  %
Total capital employed $ 7,330.5  100.0  % $ 8,270.8  100.0  %
Cash and invested cash are maintained in several operating locations outside the United States.  At September 30, 2020, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $56.6 million in Canada.  In addition, $18.4 million of cash was held in the United Kingdom and $11.0 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at September 30, 2020).  In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B
Outlook
As discussed in the Summary section on page 23, average crude oil prices recovered during the third quarter of 2020 from the low seen in the second quarter of 2020. As of close on November 4, 2020, the NYMEX WTI forward curve prices for the remainder of 2020 and 2021 were $39.15 and $41.06 per barrel, respectively; however we cannot predict what impact the ongoing COVID-19 pandemic and other economic factors may have on future commodity pricing. Lower prices are expected to result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between 146 and 154 MBOEPD, excluding NCI. If price volatility persists, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.
In response to the COVID-19 pandemic and reduced commodity prices, the Company reduced 2020 capital expenditures significantly from the original plan of $1.4 billion to $1.5 billion to a range of $680 million to $720 million, excluding NCI. The Company has also embarked on a cost reduction plan for both future direct operational expenditures and general and administrative costs. The Company will primarily fund its remaining capital program in 2020 using operating cash flow but will supplement funding where necessary with borrowings under the available revolving credit facility. The Company is closely monitoring the impact of lower commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company’s response to COVID-19 is discussed in more detail in the risk factors on page 38.  
As of November 4, 2020, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
Commodity Type Volumes
(Bbl/d) 		Price
(USD/Bbl) 		Remaining Period
Area Start Date End Date
United States WTI ¹ Fixed price derivative swap 45,000  $56.42  10/1/2020 12/31/2020
United States WTI ¹ Fixed price derivative swap 18,000  $43.31  1/1/2021 12/31/2021
1 West Texas Intermediate
Volumes
(MMcf/d) 		Price
(CAD/Mcf) 		Remaining Period
Area Commodity Type Start Date End Date
Montney Natural Gas Fixed price forward sales at AECO 59  C$2.81 10/1/2020 12/31/2020
Montney Natural Gas Fixed price forward sales at AECO 96  C$2.53 1/1/2021 12/31/2021
Montney Natural Gas Fixed price forward sales at AECO 71  C$2.50 1/1/2022 12/31/2024
Volumes
(MMcf/d) 		Price
(USD/MMBtu) 		Remaining Period
Area Commodity Type Start Date End Date
Montney Natural Gas Fixed price forward sales at Malin 20  $2.60  1/1/2021 12/31/2022
35
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2019 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 38 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.
36
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at September 30, 2020, covering certain future U.S. crude oil sales volumes in 2020.  A 10% increase in the respective benchmark price of these commodities would have decreased the net receivable associated with these derivative contracts by approximately $44.7 million, while a 10% decrease would have increased the recorded receivable by a similar amount.
There were no derivative foreign exchange contracts in place at September 30, 2020.
ITEM 4.  CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended September 30, 2020, 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.
37
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties.  These risk factors are discussed in Item 1A Risk Factors in its 2019 Form 10-K filed on February 27, 2020.  The Company has not identified any additional risk factors not previously disclosed in its 2019 Form 10-K report, except as discussed below.
Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.
Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil, natural gas liquids and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:
•the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;
•worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;
•the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;
•the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
•political instability or armed conflict in oil and natural gas producing regions;
•changes in weather patterns and climate;
•natural disasters such as hurricanes and tornadoes;
•the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
•the effect of conservation efforts;
•technological advances affecting energy consumption and energy supply;
•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
•general economic conditions worldwide.
The global downturn triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon (most notably oil) energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.
In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day (MMBLD) in May and June 2020. Production cuts of 9.6 MMBLD were extended through the end of July 2020 and cuts of 7.7 MMBLD were made for August and September. OPEC+ are expected to target cuts of 7.7 MMBLD for the remainder of 2020.
For the three months ended September 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $41 per barrel (compared to $46 and $28 and in the first and second quarters of 2020, respectively). The closing price for WTI at the end of the third quarter of 2020 was approximately $40 per barrel (compared to $30 per barrel at the end of the first quarter and $38 at the end of the second quarter), reflecting a 34% reduction from the price at the end of 2019. In comparison, WTI averaged approximately $57 in 2019, $65 in 2018 and $51 in 2017. The closing price for WTI at the end of 2019 was approximately $60 per barrel. As of close on November 4, 2020, the NYMEX WTI forward curve price for 2020 and 2021 were $39.15 and $41.06 per barrel, respectively. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the WTI prices.
38
The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended September 30, 2020 was $1.95 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of September 30, 2020, was $1.92 per MMBTU. In comparison, NYMEX natural gas was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017. The closing price for NYMEX natural gas as of December 31, 2019, was $2.19 per MMBTU. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged US$1.33 per MMBTU in 2019 and US$1.61 in 2020, up to the end of the third quarter.  The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 35 and certain variable netback contracts providing exposure to Malin and Chicago City Gate prices.
Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue for the remainder of 2020 and beyond. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize, which could impact the recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales. 
See Note L - Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.
We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See “Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”
If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.
It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.
We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company has initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.
We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.
The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) its joint venture partners and (iii) other counterparties.
Murphy is exposed to credit risk in three principle areas:
•Accounts receivable credit risk from selling its produced commodity to customers;
•Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and
39
•Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices
To mitigate these risks the Company:
•Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;
•Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.
The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.
ITEM 6. EXHIBITS
The Exhibit Index on page 42 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
40
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
MURPHY OIL CORPORATION
(Registrant)
By /s/ CHRISTOPHER D. HULSE
Christopher D. Hulse
Vice President and Controller
(Chief Accounting Officer and Duly Authorized Officer)
November 5, 2020
(Date)
41
EXHIBIT INDEX
Exhibit
No.
32
101. INS XBRL Instance Document
101. SCH XBRL Taxonomy Extension Schema Document
101. CAL XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF XBRL Taxonomy Extension Definition Linkbase Document
101. LAB XBRL Taxonomy Extension Labels Linkbase Document
101. PRE XBRL Taxonomy Extension Presentation Linkbase
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
42
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