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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, 2022
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
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, 2022 was 155,455,283.

MURPHY OIL CORPORATION
TABLE OF CONTENTS

| Page |
Part I – Financial Information |  |
Item 1. Financial Statements |  |
Consolidated Balance Sheets | 2 |
Consolidated Statements of Operations | 3 |
Consolidated Statements of Comprehensive Income | 4 |
Consolidated Statements of Cash Flows | 5 |
Consolidated Statements of Stockholders’ Equity | 6 |
Notes to Consolidated Financial Statements | 7 |
Note A – Nature of Business and Interim Financial Statements | 7 |
Note B – New Accounting Principles and Recent Accounting Pronouncements | 7 |
Note C – Revenue from Contracts with Customers | 8 |
Note D – Property, Plant and Equipment | 10 |
Note E – Assets Held for Sale and Discontinued Operations | 12 |
Note F – Financing Arrangements and Debt | 12 |
Note G – Other Financial Information | 13 |
Note H – Employee and Retiree Benefit Plans | 14 |
Note I – Incentive Plans | 14 |
Note J – Earnings Per Share | 16 |
Note K – Income Taxes | 16 |
Note L – Financial Instruments and Risk Management | 17 |
Note M – Accumulated Other Comprehensive Loss | 19 |
Note N – Environmental and Other Contingencies | 19 |
Note O – Business Segments | 20 |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 22 |
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 35 |
Item 4. Controls and Procedures | 35 |
Part II – Other Information | 36 |
Item 1. Legal Proceedings | 36 |
Item 1A. Risk Factors | 36 |
Item 6. Exhibits | 36 |
Signature | 37 |

1

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

(Thousands of dollars) | September 30, 2022 |  | December 31, 2021
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 465,998 |  |  | 521,184 |
Accounts receivable, net | 385,153 |  |  | 258,150 |
Inventories | 53,265 |  |  | 54,198 |
Prepaid expenses | 39,633 |  |  | 31,925 |
Assets held for sale | 7,538 |  |  | 15,453 |
Total current assets | 951,587 |  |  | 880,910 |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,220,651 in 2022 and $12,457,851 in 2021 | 8,249,387 |  |  | 8,127,852 |
Operating lease assets | 798,119 |  |  | 881,389 |
Deferred income taxes | 196,894 |  |  | 385,516 |
Deferred charges and other assets | 33,227 |  |  | 29,273 |
Total assets | $ | 10,229,214 |  |  | 10,304,940 |
LIABILITIES AND EQUITY |  |  |
Current liabilities |  |  |
Current maturities of long-term debt, finance lease | $ | 678 |  |  | 654 |
Accounts payable | 539,576 |  |  | 623,129 |
Income taxes payable | 38,701 |  |  | 19,951 |
Other taxes payable | 30,898 |  |  | 20,306 |
Operating lease liabilities | 166,908 |  |  | 139,427 |
Other accrued liabilities | 435,740 |  |  | 360,859 |
Total current liabilities | 1,212,501 |  |  | 1,164,326 |
Long-term debt, including finance lease obligation | 2,022,976 |  |  | 2,465,414 |
Asset retirement obligations | 848,607 |  |  | 839,776 |
Deferred credits and other liabilities | 429,200 |  |  | 570,574 |
Non-current operating lease liabilities | 648,286 |  |  | 761,162 |
Deferred income taxes | 188,046 |  |  | 182,892 |
Total liabilities | 5,349,616 |  |  | 5,984,144 |
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 2022 and 195,100,628 shares in 2021 | 195,101 |  |  | 195,101 |
Capital in excess of par value | 887,730 |  |  | 926,698 |
Retained earnings | 5,894,965 |  |  | 5,218,670 |
Accumulated other comprehensive loss | (653,828) |  |  | (527,711) |
Treasury stock | (1,615,027) |  |  | (1,655,447) |
Murphy Shareholders' Equity | 4,708,941 |  |  | 4,157,311 |
Noncontrolling interest | 170,657 |  |  | 163,485 |
Total equity | 4,879,598 |  |  | 4,320,796 |
Total liabilities and equity | $ | 10,229,214 |  |  | 10,304,940 |

See Notes to Consolidated Financial Statements, page 7.
2

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
(Thousands of dollars, except per share amounts) | 2022 |  | 2021 |  | 2022 |  | 2021
Revenues and other income |  |  |  |  |  |  |
Revenue from production | $ | 1,120,909 |  |  | 687,549 |  | $ | 3,101,736 |  |  | 2,038,905 |
Sales of purchased natural gas | 45,500 |  |  | — |  |  | 132,285 |  |  | — |
Total revenue from sales to customers | 1,166,409 |  |  | 687,549 |  |  | 3,234,021 |  |  | 2,038,905 |
Gain (Loss) on derivative instruments | 115,191 |  |  | (59,164) |  |  | (308,654) |  |  | (499,794) |
Gain on sale of assets and other income | 21,825 |  |  | 2,315 |  |  | 32,076 |  |  | 21,217 |
Total revenues and other income | 1,303,425 |  |  | 630,700 |  |  | 2,957,443 |  |  | 1,560,328 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 198,710 |  |  | 130,131 |  |  | 482,887 |  |  | 403,708 |
Severance and ad valorem taxes | 15,140 |  |  | 11,670 |  |  | 47,340 |  |  | 32,215 |
Transportation, gathering and processing | 55,348 |  |  | 44,588 |  |  | 152,219 |  |  | 137,196 |
Costs of purchased natural gas | 43,622 |  |  | — |  |  | 125,258 |  |  | — |
Exploration expenses, including undeveloped lease amortization | 9,491 |  |  | 24,517 |  |  | 72,208 |  |  | 49,840 |
Selling and general expenses | 29,348 |  |  | 27,210 |  |  | 90,007 |  |  | 85,826 |
Depreciation, depletion and amortization | 214,521 |  |  | 189,806 |  |  | 574,501 |  |  | 615,372 |
Accretion of asset retirement obligations | 11,286 |  |  | 12,198 |  |  | 34,725 |  |  | 34,854 |
Impairment of assets | — |  |  | — |  |  | — |  |  | 171,296 |
Other operating (income) expense | (27,129) |  |  | (32,791) |  |  | 115,726 |  |  | 58,616 |
Total costs and expenses | 550,337 |  |  | 407,329 |  |  | 1,694,871 |  |  | 1,588,923 |
Operating income (loss) from continuing operations | 753,088 |  |  | 223,371 |  |  | 1,262,572 |  |  | (28,595) |
Other income (loss) |  |  |  |  |  |  |
Other income (expense) | 18,301 |  |  | (1,593) |  |  | 21,114 |  |  | (11,459) |
Interest expense, net | (37,440) |  |  | (46,925) |  |  | (116,102) |  |  | (178,399) |
Total other loss | (19,139) |  |  | (48,518) |  |  | (94,988) |  |  | (189,858) |
Income (loss) from continuing operations before income taxes | 733,949 |  |  | 174,853 |  |  | 1,167,584 |  |  | (218,453) |
Income tax expense (benefit) | 159,451 |  |  | 36,838 |  |  | 247,574 |  |  | (62,498) |
Income (loss) from continuing operations | 574,498 |  |  | 138,015 |  |  | 920,010 |  |  | (155,955) |
Loss from discontinued operations, net of income taxes | (422) |  |  | (706) |  |  | (1,916) |  |  | (600) |
Net income (loss) including noncontrolling interest | 574,076 |  |  | 137,309 |  |  | 918,094 |  |  | (156,555) |
Less: Net income attributable to noncontrolling interest | 45,648 |  |  | 28,853 |  |  | 152,445 |  |  | 85,509 |
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 528,428 |  |  | 108,456 |  |  | $ | 765,649 |  |  | (242,064) |
INCOME (LOSS) PER COMMON SHARE – BASIC |  |  |  |  |  |  |
Continuing operations | $ | 3.40 |  |  | 0.70 |  |  | $ | 4.94 |  |  | (1.57) |
Discontinued operations | — |  |  | — |  |  | (0.01) |  |  | — |
Net income (loss) | $ | 3.40 |  |  | 0.70 |  |  | $ | 4.93 |  |  | (1.57) |
INCOME (LOSS) PER COMMON SHARE – DILUTED |  |  |  |  |  |  |
Continuing operations | $ | 3.36 |  |  | 0.70 |  |  | $ | 4.87 |  |  | (1.57) |
Discontinued operations | — |  |  | — |  |  | (0.01) |  |  | — |
Net income (loss) | $ | 3.36 |  |  | 0.70 |  |  | $ | 4.86 |  |  | (1.57) |
Cash dividends per Common share | $ | 0.250 |  |  | 0.125 |  |  | $ | 0.575 |  |  | 0.375 |
Average Common shares outstanding (thousands) |  |  |  |  |  |  |
Basic | 155,446 |  |  | 154,439 |  |  | 155,221 |  |  | 154,239 |
Diluted | 157,336 |  |  | 155,932 |  |  | 157,407 |  |  | 154,239 |

See Notes to Consolidated Financial Statements, page 7.
3

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
(Thousands of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
Net income (loss) including noncontrolling interest | $ | 574,076 |  |  | 137,309 |  |  | $ | 918,094 |  |  | (156,555) |
Other comprehensive (loss) income, net of tax |  |  |  |  |  |  |
Net (loss) gain from foreign currency translation | (102,266) |  |  | (31,308) |  |  | (135,791) |  |  | 6,534 |
Retirement and postretirement benefit plans | 3,165 |  |  | 4,653 |  |  | 9,674 |  |  | 12,935 |
Deferred loss on interest rate hedges reclassified to interest expense | — |  |  | — |  |  | — |  |  | 1,690 |
Other comprehensive (loss) income | (99,101) |  |  | (26,655) |  |  | (126,117) |  |  | 21,159 |
Comprehensive income (loss) including noncontrolling interest | $ | 474,975 |  |  | 110,654 |  |  | $ | 791,977 |  |  | (135,396) |
Less: Comprehensive income attributable to noncontrolling interest | 45,648 |  |  | 28,853 |  |  | 152,445 |  |  | 85,509 |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 429,327 |  |  | 81,801 |  |  | $ | 639,532 |  |  | (220,905) |

See Notes to Consolidated Financial Statements, page 7.
4

Table of Contents
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

| Nine Months Ended September 30,
(Thousands of dollars) | 2022 |  | 2021
Operating Activities |  |  |
Net income (loss) including noncontrolling interest | $ | 918,094 |  |  | (156,555) |
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities |  |  |
Loss from discontinued operations | 1,916 |  |  | 600 |
Depreciation, depletion and amortization | 574,501 |  |  | 615,372 |
Unsuccessful exploration well costs and previously suspended exploration costs | 35,224 |  |  | 17,899 |
Amortization of undeveloped leases | 10,651 |  |  | 13,872 |
Accretion of asset retirement obligations | 34,725 |  |  | 34,854 |
Deferred income tax (benefit) expense | 207,105 |  |  | (65,149) |
Mark to market loss on contingent consideration | 98,451 |  |  | 105,111 |
Mark to market loss (gain) on crude contracts | (138,707) |  |  | 228,497 |
Long-term non-cash compensation | 57,612 |  |  | 42,080 |
Impairment of assets | — |  |  | 171,296 |
(Gain) from sale of assets | (18,871) |  |  | — |
Net (increase) decrease in noncash working capital | (59,874) |  |  | 117,330 |
Other operating activities, net | (42,101) |  |  | (33,924) |
Net cash provided by continuing operations activities | 1,678,726 |  |  | 1,091,283 |
Investing Activities |  |  |
Property additions and dry hole costs 1 | (800,868) |  |  | (541,324) |
Acquisition of oil and gas properties 1 | (125,602) |  |  | (22,906) |
Proceeds from sales of property, plant and equipment | (2,129) |  |  | 270,038 |
Property additions for King's Quay FPS | — |  |  | (17,734) |
Net cash (required) by investing activities | (928,599) |  |  | (311,926) |
Financing Activities |  |  |
Borrowings on revolving credit facility | 300,000 |  |  | 165,000 |
Repayment of revolving credit facility | (300,000) |  |  | (365,000) |
Retirement of debt | (446,032) |  |  | (726,358) |
Debt issuance, net of cost | — |  |  | 541,913 |
Early redemption of debt cost | (5,419) |  |  | (36,756) |
Distributions to noncontrolling interest | (145,273) |  |  | (100,880) |
Contingent consideration payment | (81,742) |  |  | — |
Cash dividends paid | (89,354) |  |  | (57,896) |
Withholding tax on stock-based incentive awards | (17,338) |  |  | (4,973) |
Capital lease obligation payments | (475) |  |  | (643) |
Net cash (required) by financing activities | (785,633) |  |  | (585,593) |
Cash Flows from Discontinued Operations |  |  |
Operating activities | (14,500) |  |  | — |
Net cash (required) by discontinued operations | (14,500) |  |  | — |
Effect of exchange rate changes on cash and cash equivalents | (5,180) |  |  | 697 |
Net (decrease) increase in cash and cash equivalents | (55,186) |  |  | 194,461 |
Cash and cash equivalents at beginning of period | 521,184 |  |  | 310,606 |
Cash and cash equivalents at end of period | $ | 465,998 |  |  | 505,067 |

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.
See Notes to Consolidated Financial Statements, page 7.
5

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
(Thousands of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
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, 2022 and 195,100,628 shares at September 30, 2021 |  |  |  |  |  |  |
Balance at beginning of period | 195,101 |  |  | 195,101 |  |  | 195,101 |  |  | 195,101 |
Exercise of stock options | — |  |  | — |  |  | — |  |  | — |
Balance at end of period | 195,101 |  |  | 195,101 |  |  | 195,101 |  |  | 195,101 |
Capital in Excess of Par Value |  |  |  |  |  |  |
Balance at beginning of period | 883,368 |  |  | 915,181 |  |  | 926,698 |  |  | 941,692 |
Exercise of stock options, including income tax benefits | (1,956) |  |  | (35) |  |  | (12,591) |  |  | (661) |
Restricted stock transactions and other | — |  |  | (402) |  |  | (45,169) |  |  | (38,749) |
Share-based compensation | 6,318 |  |  | 6,483 |  |  | 18,792 |  |  | 18,945 |
Balance at end of period | 887,730 |  |  | 921,227 |  |  | 887,730 |  |  | 921,227 |
Retained Earnings |  |  |  |  |  |  |
Balance at beginning of period | 5,405,400 |  |  | 4,980,428 |  |  | 5,218,670 |  |  | 5,369,538 |
Net income (loss) attributable to Murphy | 528,428 |  |  | 108,456 |  |  | 765,649 |  |  | (242,064) |
Cash dividends paid | (38,863) |  |  | (19,306) |  |  | (89,354) |  |  | (57,896) |
Balance at end of period | 5,894,965 |  |  | 5,069,578 |  |  | 5,894,965 |  |  | 5,069,578 |
Accumulated Other Comprehensive Loss |  |  |  |  |  |  |
Balance at beginning of period | (554,727) |  |  | (553,519) |  |  | (527,711) |  |  | (601,333) |
Foreign currency translation (loss) gain, net of income taxes | (102,266) |  |  | (31,308) |  |  | (135,791) |  |  | 6,534 |
Retirement and postretirement benefit plans, net of income taxes | 3,165 |  |  | 4,653 |  |  | 9,674 |  |  | 12,935 |
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | — |  |  | — |  |  | — |  |  | 1,690 |
Balance at end of period | (653,828) |  |  | (580,174) |  |  | (653,828) |  |  | (580,174) |
Treasury Stock |  |  |  |  |  |  |
Balance at beginning of period | (1,616,340) |  |  | (1,656,591) |  |  | (1,655,447) |  |  | (1,690,661) |
Awarded restricted stock, net of forfeitures | — |  |  | 343 |  |  | 32,297 |  |  | 33,888 |
Exercise of stock options | 1,313 |  |  | 24 |  |  | 8,123 |  |  | 549 |
Balance at end of period – 39,645,345 shares of Common Stock in 2022 and 40,656,661 shares of Common Stock in 2021, at cost | (1,615,027) |  |  | (1,656,224) |  |  | (1,615,027) |  |  | (1,656,224) |
Murphy Shareholders’ Equity | 4,708,941 |  |  | 3,949,508 |  |  | 4,708,941 |  |  | 3,949,508 |
Noncontrolling Interest |  |  |  |  |  |  |
Balance at beginning of period | 175,428 |  |  | 161,228 |  |  | 163,485 |  |  | 179,810 |
Net income attributable to noncontrolling interest | 45,648 |  |  | 28,853 |  |  | 152,445 |  |  | 85,509 |
Distributions to noncontrolling interest owners | (50,419) |  |  | (25,642) |  |  | (145,273) |  |  | (100,880) |
Balance at end of period | 170,657 |  |  | 164,439 |  |  | 170,657 |  |  | 164,439 |
Total Equity | $ | 4,879,598 |  |  | 4,113,947 |  |  | $ | 4,879,598 |  |  | 4,113,947 |

See Notes to Consolidated Financial Statements, page 7.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas exploration and production company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.
In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) acquisition, we hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated as Murphy is not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, 2022, our maximum exposure to loss was $3.2 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2022 and December 31, 2021, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2022 and 2021, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2021 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, 2022, are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Income Taxes. In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. The Company adopted this guidance in the first quarter of 2021 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
None affecting the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM) as prescribed by ASC 810-10-45.
U.S. - In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico (GOM). Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load, based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-month periods ended September 30, 2022, and 2021, the Company recognized $1,166 million and $687.5 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.
For the nine-month periods ended September 30, 2022, and 2021, the Company recognized $3,234.0 million and $2,038.9 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
(Thousands of dollars) |  | 2022 |  | 2021 |  | 2022 |  | 2021
Net crude oil and condensate revenue |  |  |  |  |  |  |
United States | Onshore | $ | 247,562 |  |  | 167,010 |  |  | $ | 684,099 |  |  | 464,767 |
| Offshore | 597,242 |  |  | 340,001 |  |  | 1,675,389 |  |  | 1,079,418 |
Canada | Onshore | 29,445 |  |  | 29,110 |  |  | 106,559 |  |  | 89,708 |
| Offshore | 30,030 |  |  | 20,499 |  |  | 97,216 |  |  | 70,333 |
Other |  | 4,867 |  |  | — |  |  | 18,503 |  |  | — |
Total crude oil and condensate revenue | 909,146 |  |  | 556,620 |  |  | 2,581,766 |  |  | 1,704,226 |
Net natural gas liquids revenue |  |  |  |  |  |  |
United States | Onshore | 18,288 |  |  | 16,356 |  |  | 53,035 |  |  | 33,480 |
| Offshore | 16,079 |  |  | 11,046 |  |  | 48,151 |  |  | 31,866 |
Canada | Onshore | 4,932 |  |  | 4,501 |  |  | 14,800 |  |  | 11,728 |
Total natural gas liquids revenue | 39,299 |  |  | 31,903 |  |  | 115,986 |  |  | 77,074 |
Net natural gas revenue |  |  |  |  |  |  |
United States | Onshore | 21,009 |  |  | 11,127 |  |  | 51,412 |  |  | 24,442 |
| Offshore | 52,143 |  |  | 17,444 |  |  | 121,911 |  |  | 56,855 |
Canada | Onshore | 99,312 |  |  | 70,455 |  |  | 230,661 |  |  | 176,308 |
Total natural gas revenue | 172,464 |  |  | 99,026 |  |  | 403,984 |  |  | 257,605 |
Revenue from production | 1,120,909 |  |  | 687,549 |  |  | 3,101,736 |  |  | 2,038,905 |
Sales of purchased natural gas |  |  |  |  |  |  |
United States | Offshore | — |  |  | — |  |  | 181 |  |  | — |
Canada | Onshore | 45,500 |  |  | — |  |  | 132,104 |  |  | — |
Total sales of purchased natural gas | 45,500 |  |  | — |  |  | 132,285 |  |  | — |
Total revenue from sales to customers | 1,166,409 |  |  | 687,549 |  |  | 3,234,021 |  |  | 2,038,905 |
Gain (Loss) on derivative instruments | 115,191 |  |  | (59,164) |  |  | (308,654) |  |  | (499,794) |
Gain on sale of assets and other income | 21,825 |  |  | 2,315 |  |  | 32,076 |  |  | 21,217 |
Total revenues and other income | $ | 1,303,425 |  |  | 630,700 |  |  | $ | 2,957,443 |  |  | 1,560,328 |

In 2022, the Company included additional line items on the face of the Consolidated Statements of Operations to report Sales of purchased natural gas and Costs of purchased natural gas. Sales and purchases of natural gas are reported on a gross basis when Murphy takes control of the products and has risks and rewards of ownership.
Contract Balances and Asset Recognition
As of September 30, 2022, and December 31, 2021, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $210.1 million and $169.8 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, the Company did
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any revenue contracts that have financing components as of September 30, 2022.
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.
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.
As of September 30, 2022, 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, 2022
Location |  | Commodity |  | End Date |  | Description |  | Approximate Volumes
U.S. |  | Natural Gas and NGL |  | Q2 2023 |  | Deliveries from dedicated acreage in Eagle Ford |  | As produced
Canada |  | Natural Gas |  | Q4 2022 |  | Contracts to sell natural gas at USD index pricing |  | 8 MMCFD
Canada |  | Natural Gas |  | Q4 2022 |  | Contracts to sell natural gas at CAD fixed prices |  | 5 MMCFD
Canada |  | Natural Gas |  | Q4 2022 |  | Contracts to sell natural gas at USD fixed pricing |  | 20 MMCFD
Canada |  | Natural Gas |  | Q4 2023 |  | Contracts to sell natural gas at USD index pricing |  | 25 MMCFD
Canada |  | Natural Gas |  | Q4 2023 |  | Contracts to sell natural gas at CAD fixed prices |  | 38 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at USD index pricing |  | 31 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at CAD fixed prices |  | 100 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at CAD fixed prices |  | 34 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at USD fixed pricing |  | 15 MMCFD
Canada |  | Natural Gas |  | Q4 2026 |  | Contracts to sell natural gas at USD index pricing |  | 49 MMCFD
Canada |  | NGL |  | Q3 2023 |  | Contracts to sell natural gas liquids at CAD pricing |  | 952 BOED

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)
As of September 30, 2022, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $181.5 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2022 and 2021.

(Thousands of dollars) | 2022 |  | 2021
Beginning balance at January 1 | $ | 179,481 |  |  | 181,616 |
Additions pending the determination of proved reserves | 22,275 |  |  | 5,007 |
Capitalized exploratory well costs charged to expense | (20,295) |  |  | — |
Balance at September 30 | $ | 181,461 |  |  | 186,623 |

The capitalized well costs charged to expense during 2022 represent expenditures related to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil. There were no hydrocarbons found in this well.
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,
| 2022 |  | 2021
(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 | $ | 8,851 |  |  | 2 |  |  | 2 |  |  | 3,297 |  |  | 2 |  |  | 2 |
One to two years | 8,489 |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | — |
Two to three years | — |  |  | — |  |  | — |  |  | 53,078 |  |  | 5 |  |  | 5 |
Three years or more | 164,121 |  |  | 6 |  |  | 3 |  |  | 130,248 |  |  | 6 |  |  | — |
| $ | 181,461 |  |  | 10 |  |  | 7 |  |  | 186,623 |  |  | 13 |  |  | 7 |

Of the $172.6 million of exploratory well costs capitalized more than one year at September 30, 2022, $95.5 million is in Vietnam, $54.9 million is in the U.S., $15.5 million is in Mexico, $2.8 million is in Brunei, and $3.9 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
There were no impairments in the first nine months of 2022. In the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with partners, of operating and production plans at end of the first quarter 2021. Later in 2021, the Company sanctioned an asset life extension project and acquired an additional 7.525% working interest at Terra Nova following a commercial agreement to extend the life of the field.
Divestments
During the third quarter of 2022, the Company completed the disposition of its 62.5% operated working interest of the Thunder Hawk field for a purchase price of $20.0 million, less closing adjustments of $22.2 million, resulting in a total net payment to the buyer of $2.2 million. Additionally, the buyer assumed the asset retirement obligations of approximately $47.9 million. An $18.8 million gain on sale was recorded in the period related to the sale. Also in the third quarter, the Company completed the disposition of the CA-2 asset in Brunei for contingent consideration valued at approximately $8.7 million. No gain or loss was recorded related to this sale.
During the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the Company for previously incurred capital expenditures.
Acquisitions
In August 2022, the Company acquired an additional working interest of 3.37% in the Lucius field for a purchase price of $77.1 million, net of closing adjustments.
In June 2022, the Company acquired an additional working interest of 11.0% in the Kodiak field for a purchase price of $48.5 million, net of closing adjustments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)
In the second quarter of 2021, the Company acquired an additional 3.5% working interest in the Lucius field for a purchase price of $22.5 million, net of closing adjustments.
Note E – Assets Held for Sale and Discontinued Operations
The Company has accounted for its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2022 and 2021 were as follows:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
(Thousands of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
Revenues | $ | — |  |  | 144 |  |  | $ | 10 |  |  | 801 |
Costs and expenses |  |  |  |  |  |  |
Other costs and expenses | 422 |  |  | 850 |  |  | 1,926 |  |  | 1,401 |
Loss before taxes | (422) |  |  | (706) |  |  | (1,916) |  |  | (600) |
Income tax expense | — |  |  | — |  |  | — |  |  | — |
Loss from discontinued operations | $ | (422) |  |  | (706) |  |  | $ | (1,916) |  |  | (600) |

In September 2022, the Company sold its share of Brunei block CA-2 to Petronas Carigali Brunei Ltd (see Note D for additional information). The remaining balance of assets held for sale on the Consolidated Balance Sheet as of September 30, 2022 consists only of the Company’s former headquarters office building in El Dorado, Arkansas. As of December 31, 2021, assets held for sale includes the carrying value of the net property, plant and equipment of the CA-2 project in Brunei, and the Company’s former headquarters office building in El Dorado, Arkansas.

(Thousands of dollars) | September 30, 2022 |  | December 31, 2021
Current assets |  |  |
Property, plant, and equipment, net | 7,538 |  |  | 15,453 |
Total current assets associated with assets held for sale | $ | 7,538 |  |  | 15,453 |

Note F – Financing Arrangements and Debt
As of September 30, 2022, 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, 2022, the Company had no outstanding borrowings under the RCF and $53.9 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2022, the interest rate in effect on borrowings under the facility was 4.84%. At September 30, 2022 and 2021, the Company was in compliance with all covenants related to the RCF.
In September 2022, the Company paid $5.5 million to complete an open market repurchase of $7.1 million aggregate principal amount of its 6.125% senior notes due 2042 (2042 Notes). There were no additional cash costs related to the September 2022 debt extinguishment on the 2042 Notes for the three months and nine months ended September 30, 2022.
In August 2022, the Company redeemed the remaining $42.4 million of its 6.875% senior notes due in 2024 (2024 Notes) and tendered $100.0 million and $98.1 million aggregate principal amount of its 5.750% and 6.375% senior notes due 2025 and 2028 (2025 Notes and 2028 Notes), respectively. The total cost of the debt extinguishment of $4.0 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months and nine months ended September 30, 2022. The debt extinguishment on the 2025 and 2028 Notes had cash costs of $2.0 million and is shown as a financing activity on the Consolidated Statement of Cash Flows for the three months and nine months ended September 30, 2022.
In June 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% 2024 Notes. The cost of the debt extinguishment of $4.3 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2022. The cash costs of $3.4 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2022.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)
In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022; collectively the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
In August 2021, the Company redeemed $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2024.
On October 31, 2022, the Company issued a notice of partial redemption with respect to $200.0 million aggregate principal amount of its 5.750% 2025 Notes. The Company will redeem the 2025 Notes at the applicable redemption price set forth in the indenture governing the 2025 Notes, plus accrued and unpaid interest, if any, to, but not including, the date of redemption. The redemption date of the 2025 Notes will be November 30, 2022.
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.

| Nine Months Ended September 30,
(Thousands of dollars) | 2022 |  | 2021
Net (increase) decrease in operating working capital, excluding cash and cash equivalents: |  |  |
(Increase) decrease in accounts receivable ¹ | $ | (130,792) |  |  | 75,100 |
(Increase) decrease in inventories | (410) |  |  | 9,718 |
(Increase) in prepaid expenses | (8,561) |  |  | (6,682) |
Increase in accounts payable and accrued liabilities ¹ | 61,139 |  |  | 40,687 |
Increase (decrease) in income taxes payable | 18,750 |  |  | (1,493) |
Net (increase) decrease in noncash operating working capital | $ | (59,874) |  |  | 117,330 |
Supplementary disclosures: |  |  |
Cash income taxes paid, net of refunds | $ | 16,493 |  |  | 1,685 |
Interest paid, net of amounts capitalized of $13.2 million in 2022 and $11.6 million in 2021 | 112,332 |  |  | 127,793 |
Non-cash investing activities: |  |  |
Asset retirement costs capitalized 2 | $ | 29,327 |  |  | 36,300 |
Decrease in capital expenditure accrual | 34,853 |  |  | 31,301 |

1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.
2 2021 Excludes non-cash capitalized cost offset by Terra Nova impairment of $74.4 million and a gain in other operating income of $71.8 million following a commercial agreement to sanction an asset life extension project at Terra Nova in the third quarter of 2021, which extended the life of Terra Nova by approximately 10 years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2022 and 2021.

| Three Months Ended September 30,
| Pension Benefits |  | Other Postretirement Benefits
(Thousands of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
Service cost | $ | 2,129 |  |  | 1,770 |  |  | $ | 292 |  |  | 328 |
Interest cost | 5,163 |  |  | 4,258 |  |  | 574 |  |  | 521 |
Expected return on plan assets | (7,999) |  |  | (6,038) |  |  | — |  |  | — |
Amortization of prior service cost (credit) | 582 |  |  | 155 |  |  | (133) |  |  | — |
Recognized actuarial loss (gain) | 3,822 |  |  | 5,269 |  |  | (77) |  |  | (8) |
Net periodic benefit expense | $ | 3,697 |  |  | 5,414 |  |  | $ | 656 |  |  | 841 |
| Nine Months Ended September 30,
| Pension Benefits |  | Other Postretirement Benefits
(Thousands of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
Service cost | $ | 6,387 |  |  | 5,306 |  |  | $ | 876 |  |  | 981 |
Interest cost | 15,545 |  |  | 12,844 |  |  | 1,722 |  |  | 1,563 |
Expected return on plan assets | (24,091) |  |  | (18,326) |  |  | — |  |  | — |
Amortization of prior service cost (credit) | 1,761 |  |  | 467 |  |  | (399) |  |  | — |
Recognized actuarial loss (gain) | 11,466 |  |  | 15,829 |  |  | (232) |  |  | (23) |
Net periodic benefit expense | $ | 11,068 |  |  | 16,120 |  |  | $ | 1,967 |  |  | 2,521 |

The components of net periodic benefit expense, other than the service cost, are recorded in Other income (expense) in the Consolidated Statements of Operations.
During the nine-month period ended September 30, 2022, the Company made contributions of $30.7 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2022 for the Company’s defined benefit pension and postretirement plans is anticipated to be $11.9 million.
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The Annual Incentive Plan (AIP) 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 AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of five million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the 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 the Plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I – Incentive Plans (Contd.)
During the first nine months of 2022, the Committee granted the following awards from the 2020 Long-Term Plan:
2020 Long-Term Incentive Plan

Type of Award | Number of Awards Granted |  | Grant Date |  | Grant Date Fair Value |  | Valuation Methodology
Performance Based RSUs 1 | 580,600 |  |  | February 1, 2022 |  | $ | 47.37 |  |  | Monte Carlo
Performance Based RSUs 1 | 15,100 |  |  | July 1, 2022 |  | $ | 37.77 |  |  | Monte Carlo
Time Based RSUs 2 | 273,400 |  |  | February 1, 2022 |  | $ | 32.12 |  |  | Average Stock Price
Time Based RSUs 2 | 5,000 |  |  | July 1, 2022 |  | $ | 29.80 |  |  | Average Stock Price
Cash Settled RSUs 3 | 674,300 |  |  | February 1, 2022 |  | $ | 32.12 |  |  | Average Stock Price

1 Performance based RSUs are scheduled to vest over a three year performance period.
2 Time based RSUs are generally scheduled to vest over three years from the date of grant.
3 Cash settled RSUs are generally scheduled to vest over three years from the date of grant.
The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
The 2021 Stock Plan for Non-Employee Directors (2021 NED Plan) permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.
During the first nine months of 2022, the Committee granted the following awards to Non-Employee Directors:
2021 Stock Plan for Non-Employee Directors

Type of Award | Number of Awards Granted |  | Grant Date |  | Grant Date Fair Value |  | Valuation Methodology
Time Based RSUs 1 | 73,092 |  |  | February 2, 2022 |  | $ | 32.84 |  |  | Closing Stock Price

1 Non-employee directors time-based RSUs are scheduled to vest in February 2023.
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, 2022.
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) | 2022 |  | 2021
Compensation charged against income before tax benefit | $ | 43,216 |  |  | 29,145 |
Related income tax benefit recognized in income | 6,872 |  |  | 4,120 |

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note J – Earnings Per Share
Net income (loss) 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, 2022 and 2021. 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) | 2022 |  | 2021 |  | 2022 |  | 2021
Basic method | 155,446,201 |  |  | 154,439,313 |  |  | 155,220,945 |  |  | 154,239,440 |
Dilutive stock options and restricted stock units ¹ | 1,889,972 |  |  | 1,492,949 |  |  | 2,185,957 |  |  | — |
Diluted method | 157,336,173 |  |  | 155,932,262 |  |  | 157,406,902 |  |  | 154,239,440 |

1 Due to a net loss recognized by the Company for the nine-month period ended September 30, 2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2022 |  | 2021 |  | 2022 |  | 2021
Antidilutive stock options excluded from diluted shares | — |  |  | 1,316,222 |  |  | 163,800 |  |  | 1,502,758 |
Weighted average price of these options | $ | — |  |  | $ | 34.42 |  |  | $ | 49.65 |  |  | $ | 34.97 |

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, 2022 and 2021, the Company’s effective income tax rates were as follows:

| 2022 |  | 2021
Three months ended September 30, | 21.7% |  | 21.1%
Nine months ended September 30, | 21.2% |  | 28.6%

The effective tax rate for the three-month period ended September 30, 2022, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the three-month period ended September 30, 2021, was above the statutory tax rate of 21% primarily due to income generated in Canada, which has a higher tax rate, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax rate on income.
The effective tax rate for the nine-month period ended September 30, 2022, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were mostly offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the nine-month period ended September 30, 2021, was above the statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, which has the impact of increasing the effective tax rate on an overall loss.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K– Income Taxes (Contd.)
or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of September 30, 2022, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; and Malaysia – 2014. Following the sale in 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments, such as swap and zero-cost commodity price collar contracts, to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.
Commodity Price Risks
The Company has entered into crude oil swap and collar contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also mature monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.
At September 30, 2022, volumes per day associated with outstanding crude oil derivative contracts and the weighted average prices for these contracts are as follows:

|  |  |  | 2022
NYMEX WTI swap contracts: |  |  |  |
Volume per day (Bbl): |  |  |  | 20,000 |
Price per Bbl: |  |  |  | $ | 44.88 |
NYMEX WTI collar contracts: |  |  |  |
Volume per day (Bbl): |  |  |  | 25,000 |
Price per Bbl: |  |  |  |
Average Ceiling: |  |  |  | $ | 75.20 |
Average Floor: |  |  |  | $ | 63.24 |

Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at September 30, 2022 and 2021.
At September 30, 2022 and December 31, 2021, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

(Thousands of dollars) |  | Asset (Liability) Derivatives Fair Value
Type of Derivative Contract |  | Balance Sheet Location |  | September 30, 2022 |  | December 31, 2021
Commodity swaps |  | Accounts payable |  | $ | (84,933) |  |  | (239,882) |
Commodity collars |  | Accounts payable |  | (20,954) |  |  | (19,533) |
Commodity collars |  | Accounts receivable |  | — |  |  | 4,280 |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
For the three-month and nine-month periods ended September 30, 2022 and 2021, 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 |  |  | 2022 |  | 2021 |  | 2022 |  | 2021
Commodity swaps |  | Gain (Loss) on derivative instruments |  | $ | 50,089 |  |  | (43,235) |  |  | $ | (152,822) |  |  | (483,865) |
Commodity collars |  | Gain (Loss) on derivative instruments |  | 65,102 |  |  | (15,929) |  |  | (155,832) |  |  | (15,929) |

Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2022 and December 31, 2021, are presented in the following table.

|  | September 30, 2022 |  | December 31, 2021
(Thousands of dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity collars |  | $ | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4,280 |  |  | — |  |  | 4,280 |
|  | $ | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4,280 |  |  | — |  |  | 4,280 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps |  | $ | — |  |  | 84,933 |  |  | — |  |  | 84,933 |  |  | — |  |  | 239,882 |  |  | — |  |  | 239,882 |
Commodity collars |  | — |  |  | 20,954 |  |  | — |  |  | 20,954 |  |  | — |  |  | 19,533 |  |  | — |  |  | 19,533 |
Contingent consideration |  | — |  |  | — |  |  | 212,860 |  |  | 212,860 |  |  | — |  |  | — |  |  | 196,151 |  |  | 196,151 |
Nonqualified employee savings plan |  | 15,642 |  |  | — |  |  | — |  |  | 15,642 |  |  | 16,962 |  |  | — |  |  | — |  |  | 16,962 |
|  | $ | 15,642 |  |  | 105,887 |  |  | 212,860 |  |  | 334,389 |  |  | 16,962 |  |  | 259,415 |  |  | 196,151 |  |  | 472,528 |

The fair value of commodity (WTI crude oil) swaps was based on active market quotes for WTI crude oil. The fair value of commodity (WTI crude oil) collars was determined using an option pricing model. The before tax income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (Loss) on derivative instruments in the Consolidated Statements of Operations.
The contingent consideration, related to 2018 and 2019 U.S. Gulf of Mexico acquisitions, is valued using a Monte Carlo simulation model. For the nine months ended September 30, 2022 and 2021, the pre-tax income effect of changes in the fair value of the contingent consideration was an expense of $98.5 million and $105.1 million respectively and is recorded in Other operating (income) expense in the Consolidated Statements of Operations. In the nine months ended September 30, 2022, the pre-tax income effect of changes in the fair value of the contingent consideration exclude cash payments of $81.7 million, which reduced the value of the contingent consideration liability. Contingent consideration is payable annually in years 2022 to 2026.
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 pre-tax income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
The 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, 2022 and December 31, 2021.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2021 and September 30, 2022 and the changes during the nine-month period ended September 30, 2022, are presented net of taxes in the following table.

(Thousands of dollars) | Foreign Currency Translation Gains (Losses) |  | Retirement and Postretirement Benefit Plan Adjustments |  |  |  | Total
Balance at December 31, 2021 | $ | (311,895) |  |  | (215,816) |  |  |  |  | (527,711) |
Components of other comprehensive income (loss): |  |  |  |  |  |  |
Before reclassifications to income and retained earnings | (135,791) |  |  | — |  |  |  |  | (135,791) |
Reclassifications to income | — |  |  | 9,674 |  | ¹ |  |  | 9,674 |
Net other comprehensive income (loss) | (135,791) |  |  | 9,674 |  |  |  |  | (126,117) |
Balance at September 30, 2022 | $ | (447,686) |  |  | (206,142) |  |  |  |  | (653,828) |

1 Reclassifications before taxes of $12,293 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2022. See Note H for additional information. Related income taxes of $2,619 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2022.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.
ENVIRONMENTAL, HEALTH AND SAFETY MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.
Violation of environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable laws and regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings.
There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and greenhouse gas emissions (including methane emissions). For example, the Inflation Reduction Act of 2022 contains provisions that impose fees for excess methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note O – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on commodity price derivatives), interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

|  | Total Assets at September 30, 2022 |  | Three Months Ended September 30, 2022 |  | Three Months Ended September 30, 2021
(Millions of dollars) |  | External Revenues |  | Income (Loss) |  | External Revenues |  | Income (Loss)
Exploration and production ¹ |  |  |  |  |  |  |  |  |  |
United States |  | $ | 6,901.0 |  |  | 973.8 |  |  | 481.5 |  |  | 565.2 |  |  | 168.1 |
Canada |  | 2,076.0 |  |  | 209.6 |  |  | 41.4 |  |  | 124.6 |  |  | 73.9 |
Other |  | 237.4 |  |  | 4.8 |  |  | (5.8) |  |  | — |  |  | (5.2) |
Total exploration and production |  | 9,214.4 |  |  | 1,188.2 |  |  | 517.1 |  |  | 689.8 |  |  | 236.8 |
Corporate |  | 1,014.0 |  |  | 115.2 |  |  | 57.4 |  |  | (59.1) |  |  | (98.8) |
Continuing operations |  | 10,228.4 |  |  | 1,303.4 |  |  | 574.5 |  |  | 630.7 |  |  | 138.0 |
Discontinued operations, net of tax |  | 0.8 |  |  | — |  |  | (0.4) |  |  | — |  |  | (0.7) |
Total |  | $ | 10,229.2 |  |  | 1,303.4 |  |  | 574.1 |  |  | 630.7 |  |  | 137.3 |
|  |  |  | Nine Months Ended September 30, 2022 |  | Nine Months Ended September 30, 2021
(Millions of dollars) |  |  | External Revenues |  | Income (Loss) |  | External Revenues |  | Income (Loss)
Exploration and production ¹ |  |  |  |  |  |  |  |  |  |
United States |  |  |  | $ | 2,659.2 |  |  | 1,225.9 |  |  | 1,704.4 |  |  | 481.8 |
Canada |  |  |  | 582.3 |  |  | 111.3 |  |  | 349.2 |  |  | (37.7) |
Other |  |  |  | 18.5 |  |  | (53.5) |  |  | — |  |  | (22.5) |
Total exploration and production |  |  |  | 3,260.0 |  |  | 1,283.7 |  |  | 2,053.6 |  |  | 421.6 |
Corporate |  |  |  | (302.6) |  |  | (363.7) |  |  | (493.3) |  |  | (577.6) |
Continuing operations |  |  |  | 2,957.4 |  |  | 920.0 |  |  | 1,560.3 |  |  | (156.0) |
Discontinued operations, net of tax |  |  |  | — |  |  | (1.9) |  |  | — |  |  | (0.6) |
Total |  |  |  | $ | 2,957.4 |  |  | 918.1 |  |  | 1,560.3 |  |  | (156.6) |

1 Additional details about results of oil and natural gas operations are presented in the tables on page 25 and 26.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In the third quarter of 2022, crude oil and natural gas benchmark prices increased compared to the same period of 2021. Prices were higher in the third quarter of 2022 as compared to the same period in 2021, principally due to demand recovery from COVID-19 and geopolitical uncertainty and market disruption following the Russian invasion of Ukraine. Prices were lower in the third quarter 2022 as compared to the second quarter of 2022 primarily due to increased supply related to the Strategic Petroleum Reserve oil release in the third quarter, ongoing concerns related to possible economic slowdown and lower demand from China.
Similar to the overall inflation in the wider economy, the oil and gas industry, and hence the Company, is observing higher costs for goods and services used in exploration and production operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs.
For the three months ended September 30, 2022, West Texas Intermediate (WTI) crude oil prices averaged approximately $91.55 per barrel (compared to $108.41 in the second quarter of 2022 and $70.56 in the third quarter of 2021). The average price for WTI in September of 2022 was approximately $83.80 per barrel, reflecting a 17% increase from September of 2021 and a 27% reduction from the average price from June of 2022. The average price in October 2022 was $87.03 per barrel. As of close on November 1, 2022, the NYMEX WTI forward curve prices for the remainder of 2022 and 2023 were $88.37 and $81.53 per barrel, respectively.
For the three months ended September 30, 2022, the Company produced 196 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $296.1 million in capital expenditures (on a value of work done basis), which included $79.1 million in acquisition capital, primarily for an additional working interests in the GOM Lucius field. The Company reported net income from continuing operations of $574.5 million for the three months ended September 30, 2022; this amount includes income attributable to noncontrolling interest of $45.6 million and after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions and contingent consideration of $188.8 million and $24.8 million, respectively.
In the third quarter of 2022, the Company reduced debt by $247.6 million aggregate principal amount of its 6.875%, 5.750%, 6.375%, 6.125% senior notes due 2024, 2025, 2028, 2042 for the principal amount plus cash costs of $2.0 million. In 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and partially redeemed the 2024 Notes.
In August 2022, the Company acquired an additional 3.37% working interest (there is no noncontrolling interest) in the Lucius field in the Gulf of Mexico for a purchase price of $77.1 million.
For the nine months ended September 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $918.0 million in capital expenditures (on a value of work done basis), which included $125.6 million related to acquisition capital and $25.3 million related to the Cutthroat exploration well in Brazil deferred from 2021. The Company reported net income from continuing operations of $920.0 million for the nine months ended September 30, 2022. This amount includes income attributable to noncontrolling interest of $152.4 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $109.5 million and after-tax losses on contingent consideration of $77.5 million.
In the second quarter of 2022, the Company achieved first production from the at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico; with production flowing through the Murphy-operated King’s Quay floating production facility. In addition, the Company acquired an additional 11.0% working interest (with no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $48.5 million.
In the second quarter of 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% 2024 Notes for the principal amount plus cash costs of $3.4 million.
For the three months ended September 30, 2021, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 14.5 thousand barrels of oil equivalent per day (including NCI). The Company invested $110.5 million in capital expenditures (on a value of work done basis), in the three months ended September 31, 2021. The Company reported net income from continuing operations of $138.0 million for the third quarter of 2021. This amount included income attributable to noncontrolling interest of $28.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $44.1 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on contingent consideration of $22.4 million.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Summary (contd.)
For the nine months ended September 30, 2021, the Company produced 170 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI). The Company invested $568.7 million in capital expenditures (on a value of work done basis) in the nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay floating production system (which was subsequently reimbursed by Arclight). The Company reported net loss from continuing operations of $156.0 million for the nine months ended September 30, 2021. This amount included income attributable to noncontrolling interest of $85.5 million, after-tax impairment charges of $128.0 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration of $180.5 million and $83.0 million, respectively.
In the first quarter of 2021, the Company’s subsidiary, Murphy Exploration & Production Company - USA, closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of project costs from inception to closing with proceeds of $267.7 million.
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) | 2022 |  | 2021 |  | 2022 |  | 2021
Exploration and production | $ | 517.1 |  |  | 236.8 |  |  | $ | 1,283.7 |  |  | 421.6 |
Corporate and other | 57.4 |  |  | (98.8) |  |  | (363.7) |  |  | (577.6) |
Income (loss) from continuing operations | 574.5 |  |  | 138.0 |  |  | 920.0 |  |  | (156.0) |
Discontinued operations ¹ | (0.4) |  |  | (0.7) |  |  | (1.9) |  |  | (0.6) |
Net income (loss) including noncontrolling interest | $ | 574.1 |  |  | 137.3 |  |  | $ | 918.1 |  |  | (156.6) |

1 The Company has presented its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations in its consolidated financial statements.
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.

| Income (Loss)
| Three Months Ended September 30, |  | Nine Months Ended September 30,
(Millions of dollars) | 2022 |  | 2021 |  | 2022 |  | 2021
Exploration and production |  |  |  |  |  |  |
United States | $ | 481.5 |  |  | 168.1 |  |  | $ | 1,225.9 |  |  | 481.8 |
Canada | 41.4 |  |  | 73.9 |  |  | 111.3 |  |  | (37.7) |
Other | (5.8) |  |  | (5.2) |  |  | (53.5) |  |  | (22.5) |
Total | $ | 517.1 |  |  | 236.8 |  |  | $ | 1,283.7 |  |  | 421.6 |

Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
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) | 2022 |  | 2021 |  | 2022 |  | 2021
Net income (loss) attributable to Murphy (GAAP) | $ | 528.4 |  |  | 108.5 |  |  | $ | 765.6 |  |  | (242.1) |
Income tax expense (benefit) | 159.5 |  |  | 36.8 |  |  | 247.6 |  |  | (62.5) |
Interest expense, net | 37.4 |  |  | 46.9 |  |  | 116.1 |  |  | 178.4 |
Depreciation, depletion and amortization expense ¹ | 207.7 |  |  | 182.8 |  |  | 552.5 |  |  | 588.4 |
EBITDA attributable to Murphy (Non-GAAP) | 933.0 |  |  | 375.0 |  |  | 1,681.8 |  |  | 462.2 |
Mark-to-market (gain) loss on derivative instruments | (239.1) |  |  | (55.9) |  |  | (138.7) |  |  | 228.5 |
Mark-to-market (gain) loss on contingent consideration | (31.4) |  |  | 28.4 |  |  | 98.5 |  |  | 105.1 |
Foreign exchange gain | (20.7) |  |  | (2.8) |  |  | (28.7) |  |  | (1.5) |
Gain on sale of assets ¹ | (15.2) |  |  | — |  |  | (15.2) |  |  | — |
Accretion of asset retirement obligations ¹ | 10.0 |  |  | 10.8 |  |  | 30.7 |  |  | 30.8 |
Discontinued operations loss | 0.4 |  |  | 0.7 |  |  | 1.9 |  |  | 0.6 |
Impairment of assets | — |  |  | — |  |  | — |  |  | 171.3 |
Unutilized rig charges | — |  |  | 3.2 |  |  | — |  |  | 8.5 |
Asset retirement obligation gains | — |  |  | (71.8) |  |  | — |  |  | (71.8) |
Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 637.1 |  |  | 287.6 |  |  | $ | 1,630.3 |  |  | 933.7 |
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 17,525 |  |  | 14,219 |  |  | 44,973 |  |  | 43,536 |
Adjusted EBITDA per barrel of oil equivalents sold | $ | 36.35 |  |  | 20.23 |  |  | $ | 36.25 |  |  | 21.45 |

1 Depreciation, depletion, and amortization expense, gain on sale of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2022 AND 2021

(Millions of dollars) | United States 1 |  | Canada |  | Other |  | Total
Three Months Ended September 30, 2022 |  |  |  |  |  |  |
Oil and gas sales and other operating revenues | $ | 973.8 |  |  | 164.1 |  |  | 4.8 |  |  | 1,142.7 |
Sales of purchased natural gas | — |  |  | 45.5 |  |  | — |  |  | 45.5 |
Lease operating expenses | 158.8 |  |  | 39.6 |  |  | 0.3 |  |  | 198.7 |
Severance and ad valorem taxes | 14.9 |  |  | 0.3 |  |  | — |  |  | 15.2 |
Transportation, gathering and processing | 38.5 |  |  | 16.9 |  |  | — |  |  | 55.4 |
Costs of purchased natural gas | — |  |  | 43.7 |  |  | — |  |  | 43.7 |
Depreciation, depletion and amortization | 169.4 |  |  | 40.9 |  |  | 0.9 |  |  | 211.2 |
Accretion of asset retirement obligations | 8.8 |  |  | 2.4 |  |  | — |  |  | 11.2 |
Exploration expenses |  |  |  |  |  |  |
Dry holes and previously suspended exploration costs | 0.2 |  |  | — |  |  | 0.9 |  |  | 1.1 |
Geological and geophysical | 1.1 |  |  | 0.1 |  |  | 0.4 |  |  | 1.6 |
Other exploration | 1.5 |  |  | — |  |  | 2.6 |  |  | 4.1 |
| 2.8 |  |  | 0.1 |  |  | 3.9 |  |  | 6.8 |
Undeveloped lease amortization | 2.0 |  |  | 0.1 |  |  | 0.6 |  |  | 2.7 |
Total exploration expenses | 4.8 |  |  | 0.2 |  |  | 4.5 |  |  | 9.5 |
Selling and general expenses | 2.6 |  |  | 5.2 |  |  | 2.0 |  |  | 9.8 |
Other | (27.7) |  |  | 3.7 |  |  | 0.6 |  |  | (23.4) |
Results of operations before taxes | 603.7 |  |  | 56.7 |  |  | (3.5) |  |  | 656.9 |
Income tax provisions | 122.2 |  |  | 15.3 |  |  | 2.3 |  |  | 139.8 |
Results of operations (excluding Corporate segment) | $ | 481.5 |  |  | 41.4 |  |  | (5.8) |  |  | 517.1 |
Three Months Ended September 30, 2021 |  |  |  |  |  |  |
Oil and gas sales and other operating revenues | $ | 565.2 |  |  | 124.6 |  |  | — |  |  | 689.8 |
Lease operating expenses | 96.7 |  |  | 33.4 |  |  | 0.1 |  |  | 130.2 |
Severance and ad valorem taxes | 10.8 |  |  | 0.8 |  |  | — |  |  | 11.6 |
Transportation, gathering and processing | 28.4 |  |  | 16.2 |  |  | — |  |  | 44.6 |
Depreciation, depletion and amortization | 147.0 |  |  | 39.7 |  |  | 0.1 |  |  | 186.8 |
Accretion of asset retirement obligations | 9.3 |  |  | 2.9 |  |  | — |  |  | 12.2 |
Exploration expenses |  |  |  |  |  |  |
Dry holes and previously suspended exploration costs | 17.3 |  |  | — |  |  | — |  |  | 17.3 |
Geological and geophysical | — |  |  | — |  |  | 0.3 |  |  | 0.3 |
Other exploration | 1.3 |  |  | 0.1 |  |  | 0.5 |  |  | 1.9 |
| 18.6 |  |  | 0.1 |  |  | 0.8 |  |  | 19.5 |
Undeveloped lease amortization | 3.1 |  |  | 0.1 |  |  | 1.8 |  |  | 5.0 |
Total exploration expenses | 21.7 |  |  | 0.2 |  |  | 2.6 |  |  | 24.5 |
Selling and general expenses | 4.2 |  |  | 4.0 |  |  | 1.2 |  |  | 9.4 |
Other | 39.1 |  |  | (71.7) |  |  | 2.0 |  |  | (30.6) |
Results of operations before taxes | 208.0 |  |  | 99.1 |  |  | (6.0) |  |  | 301.1 |
Income tax provisions | 39.9 |  |  | 25.2 |  |  | (0.8) |  |  | 64.3 |
Results of operations (excluding Corporate segment) | $ | 168.1 |  |  | 73.9 |  |  | (5.2) |  |  | 236.8 |

1 Includes results attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2022 AND 2021

(Millions of dollars) | United States 1 |  | Canada |  | Other |  | Total
Nine Months Ended September 30, 2022 |  |  |  |  |  |  |
Oil and gas sales and other operating revenues | $ | 2,659.0 |  |  | 450.2 |  |  | 18.5 |  |  | 3,127.7 |
Sales of purchased natural gas | 0.2 |  |  | 132.1 |  |  | — |  |  | 132.3 |
Lease operating expenses | 368.2 |  |  | 113.4 |  |  | 1.2 |  |  | 482.8 |
Severance and ad valorem taxes | 46.4 |  |  | 1.0 |  |  | — |  |  | 47.4 |
Transportation, gathering and processing | 100.0 |  |  | 52.2 |  |  | — |  |  | 152.2 |
Costs of purchased natural gas | 0.2 |  |  | 125.1 |  |  | — |  |  | 125.3 |
Depreciation, depletion and amortization | 449.6 |  |  | 110.7 |  |  | 4.4 |  |  | 564.7 |
Accretion of asset retirement obligations | 27.3 |  |  | 7.3 |  |  | 0.1 |  |  | 34.7 |
Exploration expenses |  |  |  |  |  |  |
Dry holes and previously suspended exploration costs | (0.5) |  |  | — |  |  | 35.7 |  |  | 35.2 |
Geological and geophysical | 3.7 |  |  | 0.2 |  |  | 1.4 |  |  | 5.3 |
Other exploration | 5.9 |  |  | 0.4 |  |  | 14.7 |  |  | 21.0 |
| 9.1 |  |  | 0.6 |  |  | 51.8 |  |  | 61.5 |
Undeveloped lease amortization | 6.7 |  |  | 0.2 |  |  | 3.8 |  |  | 10.7 |
Total exploration expenses | 15.8 |  |  | 0.8 |  |  | 55.6 |  |  | 72.2 |
Selling and general expenses | 14.1 |  |  | 14.1 |  |  | 6.5 |  |  | 34.7 |
Other | 110.4 |  |  | 6.5 |  |  | 1.0 |  |  | 117.9 |
Results of operations before taxes | 1,527.2 |  |  | 151.2 |  |  | (50.3) |  |  | 1,628.1 |
Income tax provisions (benefits) | 301.3 |  |  | 39.9 |  |  | 3.2 |  |  | 344.4 |
Results of operations (excluding Corporate segment) | $ | 1,225.9 |  |  | 111.3 |  |  | (53.5) |  |  | 1,283.7 |
Nine months ended September 30, 2021 |  |  |  |  |  |  |
Oil and gas sales and other operating revenues | $ | 1,704.4 |  |  | 349.2 |  |  | — |  |  | 2,053.6 |
Lease operating expenses | 303.3 |  |  | 100.0 |  |  | 0.4 |  |  | 403.7 |
Severance and ad valorem taxes | 30.6 |  |  | 1.6 |  |  | — |  |  | 32.2 |
Transportation, gathering and processing | 90.5 |  |  | 46.7 |  |  | — |  |  | 137.2 |
Depreciation, depletion and amortization | 476.6 |  |  | 128.0 |  |  | 1.1 |  |  | 605.7 |
Accretion of asset retirement obligations | 27.5 |  |  | 7.4 |  |  | — |  |  | 34.9 |
Impairment of assets | — |  |  | 171.3 |  |  | — |  |  | 171.3 |
Exploration expenses |  |  |  |  |  |  |
Dry holes and previously suspended exploration costs | 17.9 |  |  | — |  |  | — |  |  | 17.9 |
Geological and geophysical | 2.7 |  |  | — |  |  | 1.3 |  |  | 4.0 |
Other exploration | 4.2 |  |  | 0.2 |  |  | 9.6 |  |  | 14.0 |
| 24.8 |  |  | 0.2 |  |  | 10.9 |  |  | 35.9 |
Undeveloped lease amortization | 7.9 |  |  | 0.2 |  |  | 5.8 |  |  | 13.9 |
Total exploration expenses | 32.7 |  |  | 0.4 |  |  | 16.7 |  |  | 49.8 |
Selling and general expenses | 15.0 |  |  | 12.0 |  |  | 4.7 |  |  | 31.7 |
Other | 133.5 |  |  | (67.7) |  |  | (1.2) |  |  | 64.6 |
Results of operations before taxes | 594.7 |  |  | (50.5) |  |  | (21.7) |  |  | 522.5 |
Income tax provisions (benefits) | 112.9 |  |  | (12.8) |  |  | 0.8 |  |  | 100.9 |
Results of operations (excluding Corporate segment) | $ | 481.8 |  |  | (37.7) |  |  | (22.5) |  |  | 421.6 |

1 Includes results attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Exploration and Production
Third quarter 2022 vs. 2021
All amounts include amount attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM), unless otherwise noted.
United States E&P operations reported earnings of $481.5 million in the third quarter of 2022 compared to income of $168.1 million in the third quarter of 2021. Results were $313.4 million favorable in the 2022 quarter compared to the 2021 period primarily due to higher revenues ($408.6 million), lower exploration expenses ($17.1 million) and other operating expense ($66.8 million), partially offset by higher lease operating expenses ($62.1 million), higher depreciation, depletion and amortization (DD&A, $22.4 million) and higher income tax expense ($82.3 million). Higher revenues were primarily due to higher commodity prices, higher production volumes from the Khaleesi and Mormont fields and lower weather related downtime. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Lower other operating expense is primarily due to favorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher lease operating expense is due to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher DD&A is a result of higher production volumes, partially offset by lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Higher income tax expense is a result of higher pre-tax profits.
Canadian E&P operations reported earnings of $41.4 million in the third quarter 2022 compared to income of $73.9 million in the third quarter of 2021. Results were unfavorable $32.5 million compared to the 2021 period primarily due to a credit of $71.8 million reported in 2021 in other operating expense as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenues from production ($39.5 million), partially offset by higher lease operating expenses ($6.2 million) and higher tax expense ($9.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas volumes at Tupper Montney. Higher lease operating expenses is primarily the result of higher volumes and related gas processing costs. Higher income tax expense is a result of higher pre-tax profits.
Other international E&P operations reported a loss from continuing operations of $5.8 million in the third quarter of 2022 compared to a loss of $5.2 million in the third quarter of 2021. The result was $0.6 million unfavorable in the 2022 period versus 2021 primarily due to higher exploration expenses and higher taxes partially offset by higher revenue from Brunei.
Nine months 2022 vs. 2021
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $1,225.9 million in the first nine months of 2022 compared to earnings of $481.8 million in the first nine months of 2021. Results were $744.1 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($954.6 million) and lower DD&A ($27.0 million), other operating expense ($23.1 million) and exploration expenses ($16.9 million) partially offset by higher income tax expense ($188.4 million), lease operating expenses ($64.9 million) and severance and ad valorem taxes ($15.8 million). Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021. Lower DD&A is a result of lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Lower other operating expenses is primarily due to a lower unfavorable mark to market revaluation on contingent consideration ($98.5 million; as a result of commodity prices increasing less drastically) from prior GOM acquisitions and no repeat of rig standby charges. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Higher income tax expense is a result of higher pre-tax income. Higher lease operating expenses relate to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale.
Canadian E&P operations reported earnings of $111.3 million in the first nine months of 2022 compared to a loss of $37.7 million in the first nine months of 2021. Results were $149.0 million favorable compared to the 2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter following an asset abandonment notice from the operator of Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in other operating expense as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue from production ($101.0 million) and lower DD&A ($17.3 million) offset by higher income tax expense ($52.7 million) and lease operating expenses ($13.4 million). Higher revenue is primarily attributable to higher realized prices and higher gas volumes (new wells added in 2022). Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay due to normal well decline.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses are due to higher gas volumes and higher processing rates.
Other international E&P operations reported a loss of $53.5 million in the first nine months of 2022 compared to a loss of $22.5 million in the prior year. Results were $31.0 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.
Corporate
Third quarter 2022 vs. 2021
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported income of $57.4 million in the third quarter of 2022 compared to a loss of $98.8 million in the third quarter of 2021. The $156.2 million favorable variance is principally due to current period gains on derivative instruments in the third quarter of 2022 compared to losses in the same 2021 period (2022: $115.2 million gain; 2021: $59.2 million loss) for a favorable variance of $174.4 million. In addition, favorable variances were recorded due to lower interest expense ($10.9 million) and favorable exchange rate gains ($18.3 million) partially offset by higher tax expense ($47.1 million). Realized and unrealized gains on derivative instruments are due to a decrease in oil prices for current (realized) and/or future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Interest charges are lower in the third quarter of 2022 due to lower overall debt in the period. Higher income tax expense is a result of higher pre-tax gains.
Nine months 2022 vs. 2021
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $363.7 million in the first nine months of 2022 compared to a loss of $577.6 million in the first nine months of 2021. The $213.9 million favorable variance is primarily due to lower losses on derivative instruments in 2022 ($191.1 million) compared to 2021 (2022: $308.7 million loss; 2021: $499.8 million loss), lower interest expense ($62.4 million) and foreign exchange gains ($31.0 million), partially offset by lower tax benefits ($66.6 million). Interest charges are lower in the first nine months of 2022 primarily due to lower overall debt and lower debt redemption premiums ($5.4 million in 2022; $36.8 million in 2021) incurred by the Company in the period. In the first nine months of 2022 the Company reduced debt by $447.6 million compared to the 2021 reduction of $726.4 million. Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Lower income tax benefit is a result of lower pre-tax losses.
Production Volumes and Prices
Third quarter 2022 vs. 2021
Total hydrocarbon production from continuing operations averaged 196,243 barrels of oil equivalent per day in the third quarter of 2022, which was 20% higher than the 163,224 barrels per day produced in third quarter 2021. The increase in production is principally due to production from the Khaleesi, Mormont and Samurai field development project that started production in the second quarter of 2022, new well production at Tupper Montney and lower weather related downtime in the third quarter of 2022.
Average crude oil and condensate production from continuing operations was 103,386 barrels per day in the third quarter of 2022 compared to 88,245 barrels per day in the third quarter of 2021. The increase of 15,141 barrels per day was associated with higher volumes in the Gulf of Mexico (15,304 barrels per day) principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. Canada production is lower (2,680 barrels per day) primarily attributable to Kaybob Duvernay well decline and planned downtime at Hibernia. Eagle Ford Shale production is higher (2,329 barrels per day) due to new wells at Karnes and Catarina. On a worldwide basis, the Company’s crude oil and condensate prices averaged $93.56 per barrel in the third quarter 2022 compared to $68.88 per barrel in the 2021 period, an increase of 36% quarter over quarter.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Total production of natural gas liquids (NGL) from continuing operations was 11,548 barrels per day in the third quarter 2022 compared to 10,391 barrels per day in the 2021 period. The increase of 1,157 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. The average sales price for U.S. NGL was $35.37 per barrel in the 2022 quarter compared to $32.01 per barrel in 2021. The average sales price for NGL in Canada was $54.40 per barrel in the 2022 quarter compared to $45.12 per barrel in 2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.
Natural gas production volumes from continuing operations averaged 487.9 million cubic feet per day (MMCFD) in the third quarter 2022 compared to 387.5 MMCFD in 2021. The increase of 100.3 MMCFD was a result of higher volumes in Canada (82.8 MMCFD) as well as higher volumes in the Gulf of Mexico (19.0 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 20 new wells at Tupper Montney since the second quarter of 2022.
Natural gas prices for the total Company averaged $3.84 per thousand cubic feet (MCF) in the 2022 quarter, versus $2.78 per MCF average in the same quarter of 2021. Average natural gas prices in the U.S. and Canada in the quarter were $8.34 and $2.75 per MCF, respectively. Average natural gas prices in Canada are lower as a result of certain fixed price sales volume contracts.
Nine months 2022 vs. 2021
Total hydrocarbon production from Exploration and Production averaged 173,260 barrels of oil equivalent per day in the first nine months of 2022, which represented a 1.8% increase from the 170,209 barrels per day produced in the first nine months of 2021. The increase is principally due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, new wells at Tupper Montney and lower weather related downtime in 2022.
Average crude oil and condensate production was 95,275 barrels per day in the first nine months of 2022 compared to 98,314 barrels per day in the first nine months of 2021. The decrease of 3,039 barrels per day was principally due to normal declines partially offset by new production from the Khaleesi, Mormont, Samurai field development project. In addition, Canada production is lower (2,517 barrels per day) due to normal field decline at Kaybob and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (1,470 barrels per day) due to normal well decline partially offset by 2022 new well production. Higher Gulf of Mexico production (475 barrels per day) due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, and lower weather related downtime in 2022 partially offset by normal declines. On a worldwide basis, the Company’s crude oil and condensate prices averaged $99.38 per barrel in the first nine months of 2022 compared to $64.19 per barrel in the 2021 period, an increase of 54.8% year over year.
Total production of natural gas liquids (NGL) was 10,621 barrels per day in the first nine months of 2022 compared to 10,498 barrels per day in the 2021 period. The average sales price for U.S. NGL was $38.30 per barrel in 2022 compared to $25.63 per barrel in 2021. The average sales price for NGL in Canada was $57.53 per barrel in 2022 compared to $37.05 per barrel in 2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.
Natural gas production volumes averaged 404.2 million cubic feet per day (MMCFD) in the first nine months of 2022 compared to 368.4 MMCFD in 2021. The increase of 35.8 MMCFD was primarily the result of higher volumes in Canada 36.3 MMCFD) and Eagle Ford Shale (1.3 MMCFD), partially offset by the Gulf of Mexico (1.8 MMCFD). The higher natural gas volumes in Canada was the result of new wells on production in the nine months of the year. Natural gas prices for the total Company averaged $3.66 per thousand cubic feet (MCF) in the first nine months of 2022, versus $2.56 per MCF average in the same period of 2021. Average realized natural gas prices in the U.S. and Canada in the quarter were $7.00 per MCF and $2.70 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.
Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table reports hydrocarbons produced during the three-month and nine-month periods ended September 30, 2022 and 2021.

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
Barrels per day unless otherwise noted | 2022 |  | 2021 |  | 2022 |  | 2021
Net crude oil and condensate |  |  |  |  |  |  |
United States | Onshore | 28,522 |  |  | 26,193 |  |  | 25,082 |  |  | 26,552 |
| Gulf of Mexico 1 | 68,315 |  |  | 53,011 |  |  | 62,380 |  |  | 61,905 |
Canada | Onshore | 3,891 |  |  | 4,963 |  |  | 4,228 |  |  | 5,598 |
| Offshore | 2,171 |  |  | 3,779 |  |  | 2,869 |  |  | 4,016 |
Other |  | 487 |  |  | 299 |  |  | 716 |  |  | 243 |
Total net crude oil and condensate - continuing operations | 103,386 |  |  | 88,245 |  |  | 95,275 |  |  | 98,314 |
Net natural gas liquids |  |  |  |  |  |  |  |
United States | Onshore | 5,782 |  |  | 5,847 |  |  | 5,268 |  |  | 5,043 |
| Gulf of Mexico 1 | 4,780 |  |  | 3,459 |  |  | 4,411 |  |  | 4,296 |
Canada | Onshore | 986 |  |  | 1,085 |  |  | 942 |  |  | 1,159 |
Total net natural gas liquids - continuing operations | 11,548 |  |  | 10,391 |  |  | 10,621 |  |  | 10,498 |
Net natural gas – thousands of cubic feet per day |  |  |  |  |  |  |
United States | Onshore | 30,054 |  |  | 31,478 |  |  | 29,032 |  |  | 27,750 |
| Gulf of Mexico 1 | 65,319 |  |  | 46,339 |  |  | 61,727 |  |  | 63,557 |
Canada | Onshore | 392,483 |  |  | 309,709 |  |  | 313,422 |  |  | 277,077 |
Total net natural gas - continuing operations | 487,856 |  |  | 387,526 |  |  | 404,181 |  |  | 368,384 |
Total net hydrocarbons - continuing operations including NCI 2,3 | 196,243 |  |  | 163,224 |  |  | 173,260 |  |  | 170,209 |
Noncontrolling interest |  |  |  |  |  |  |  |
Net crude oil and condensate – barrels per day | (7,125) |  |  | (7,546) |  |  | (7,735) |  |  | (8,834) |
Net natural gas liquids – barrels per day | (264) |  |  | (243) |  |  | (290) |  |  | (322) |
Net natural gas – thousands of cubic feet per day 2 | (2,202) |  |  | (2,331) |  |  | (2,628) |  |  | (3,498) |
Total noncontrolling interest | (7,756) |  |  | (8,178) |  |  | (8,463) |  |  | (9,739) |
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 188,487 |  |  | 155,046 |  |  | 164,797 |  |  | 160,470 |

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 reports the weighted average sales prices excluding transportation cost deductions and sales of purchased natural gas for the three-month and nine-month periods ended September 30, 2022 and 2021.

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2022 |  | 2021 |  | 2022 |  | 2021
Weighted average Exploration and Production sales prices |  |  |  |  |  |  |
Continuing operations |  |  |  |  |  |  |  |
Crude oil and condensate – dollars per barrel |  |  |  |  |  |  |
United States | Onshore | $ | 94.33 |  |  | 69.30 |  |  | $ | 99.92 |  |  | 64.16 |
| Gulf of Mexico 1 | 92.96 |  |  | 68.93 |  |  | 99.04 |  |  | 64.44 |
Canada 2 | Onshore | 82.25 |  |  | 63.76 |  |  | 92.31 |  |  | 58.70 |
| Offshore | 111.76 |  |  | 72.64 |  |  | 112.93 |  |  | 68.93 |
Other |  | 117.18 |  |  | — |  |  | 92.91 |  |  | — |
Natural gas liquids – dollars per barrel |  |  |  |  |  |  |
United States | Onshore | 34.33 |  |  | 30.37 |  |  | 36.83 |  |  | 24.29 |
| Gulf of Mexico 1 | 36.56 |  |  | 34.71 |  |  | 39.99 |  |  | 27.17 |
Canada 2 | Onshore | 54.40 |  |  | 45.12 |  |  | 57.53 |  |  | 37.05 |
Natural gas – dollars per thousand cubic feet |  |  |  |  |  |  |
United States | Onshore | 7.62 |  |  | 3.85 |  |  | 6.49 |  |  | 3.23 |
| Gulf of Mexico 1 | 8.68 |  |  | 4.09 |  |  | 7.23 |  |  | 3.28 |
Canada 2 | Onshore | 2.75 |  |  | 2.47 |  |  | 2.70 |  |  | 2.33 |

1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. See below for additional discussion and analysis of the Company’s cash flows.
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $1,678.7 million for the first nine months of 2022 compared to $1,091.3 million during the same period in 2021. The increased cash from operating activities of $587.4 million is primarily attributable to higher revenue from production ($1,062.8 million), offset by the timing of working capital settlements ($177.2 million; primarily higher revenue received in cash following the end of the quarter), offset by higher realized losses on derivative instruments ($176.1 million).
Cash Required by Investing Activities
Net cash required by investing activities was $928.6 million for the first nine months of 2022 compared to $311.9 million during the same period in 2021. In the first nine months of 2022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $48.5 million and $77.1 million, respectively (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which include amounts expensed, were $800.9 million and $541.3 million in the first nine months of 2022 and 2021, respectively. The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $267.7 million, which was sold to ArcLight.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
Total accrual basis capital expenditures are shown below.

| Nine Months Ended September 30,
(Millions of dollars) | 2022 |  | 2021
Capital Expenditures |  |  |
Exploration and production | $ | 904.1 |  |  | 556.0 |
Corporate | 13.9 |  |  | 12.7 |
Total capital expenditures | $ | 918.0 |  |  | 568.7 |

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) | 2022 |  | 2021
Property additions and dry hole costs per cash flow statements 1 | $ | 800.9 |  |  | 541.3 |
Property additions King's Quay per cash flow statements | — |  |  | 17.7 |
Acquisition of oil and gas properties 1 | 125.6 |  |  | 22.9 |
Geophysical and other exploration expenses | 20.4 |  |  | 13.3 |
Capital expenditure accrual changes and other | (28.9) |  |  | (26.6) |
Total capital expenditures | $ | 918.0 |  |  | 568.7 |

1 Certain prior-period amounts have been reclassified to conform to the current period presentation
The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Kodiak and Lucius acquisition in Gulf of Mexi co ($125.6 million), Cutthroat-1 exploration well in Brazil ($25.3 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in Gulf of Mexico, higher development drilling activities in Eagle Ford Shale and Tupper Montney assets and higher expenditures related to the asset life extension at Terra Nova.
Cash Required by Financing Activities
Net cash required by financing activities was $785.6 million for the first nine months of 2022 compared to $585.6 million during the same period in 2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024, 2025, 2028 and 2042 ($446.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($145.3 million), and cash dividends to shareholders of $0.575 per share ($89.4 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.25 per share, or $1.00 per share on an annualized basis.
As of September 30, 2022 and in the eve nt it is required to fund investing activities from borrowings, the Company has $1,546.1 million available on its committed RCF.
In first nine months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).
Working Capital
Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of September 30, 2022 was a deficit of $268.5 million, $30.4 million lower than December 31, 2021, with the decrease primarily attributable to higher accounts receivable ($127.0 million) and lower accounts payable ($83.6 million), partially offset by higher other accrued liabilities ($74.9 million), a lower cash balance ($55.2 million) and higher operating lease liabilities ($27.5 million). Higher accounts receivable are principally due to higher crude oil and gas pricing. Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
remainder of 2022 partially offset by higher revenue payables principally due to higher crude oil and gas pricing. Higher other accrued liabilities are associated with higher short term contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices and timing of payments. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project.
Capital Employed
At September 30, 2022, long-term debt of $2,023.0 million had decreased by $442.4 million compared to December 31, 2021, primarily as a result of the partial repayment of notes due 2024, 2025, 2028 and 2042 ($447.6 million). The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.1%.
A summary of capital employed at September 30, 2022 and December 31, 2021 follows.

| September 30, 2022 |  | December 31, 2021
(Millions of dollars) | Amount |  | % |  | Amount |  | %
Capital employed |  |  |  |  |  |  |
Long-term debt | $ | 2,023.0 |  |  | 30.1 | % |  | $ | 2,465.4 |  |  | 37.2 | %
Murphy shareholders' equity | 4,708.9 |  |  | 69.9 | % |  | 4,157.3 |  |  | 62.8 | %
Total capital employed | $ | 6,731.9 |  |  | 100.0 | % |  | $ | 6,622.7 |  |  | 100.0 | %

Cash and invested cash are maintained in several operating locations outside the United States. As of September 30, 2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $95.3 million in Canada. In addition, approximately $25.5 million of cash was held in Brunei, $20.9 million of cash was held in Mexico and $12.5 million of cash was held in the U.K.. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements
Outlook
As discussed in the Summary section on page 22, several factors have contributed to a lower average crude oil price during the third quarter, which directly impacts the Company’s product revenue from sales (Q3 2022 $91.55; Q2 2022 $108.41; Q3 2021 $70.56). As of close on November 1, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were lower at $88.37 and $81.53 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment, inflation and the Russia/Ukraine conflict) may have on future commodity prices. Lower prices will result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between 173.5 and 181.5 MBOEPD, excluding noncontrolling interest (NCI).
The Company’s capital expenditure spend for 2022 is expected to be between $975.0 million and $1,025.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company plans to fund its remaining capital program in 2022 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F).
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
As of November 1, 2022, 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 |  | WTI² |  | Fixed price derivative swap |  | 20,000 |  |  | $44.88 |  |  | 10/1/2022 |  | 12/31/2022

|  |  |  |  |  | Volumes (Bbl/d) |  | Average Put (USD/Bbl) |  | Average Call (USD/Bbl) |  | Remaining Period
Area |  | Commodity |  | Type |  |  |  |  | Start Date |  | End Date
United States |  | WTI² |  | Derivative collars |  | 25,000 |  |  | $63.24 |  |  | $75.20 |  |  | 10/1/2022 |  | 12/31/2022

1 West Texas Intermediate

|  |  |  |  |  | Volumes (MMcf/d) |  | Price/Mcf |  | Remaining Period
Area |  | Commodity |  | Type |  |  |  | Start Date |  | End Date
Canada |  | Natural Gas |  | Fixed price forward sales |  | 247 |  |  | C$2.34 |  | 10/1/2022 |  | 10/31/2022
Canada |  | Natural Gas |  | Fixed price forward sales |  | 266 |  |  | C$2.36 |  | 11/1/2022 |  | 12/31/2022
Canada |  | Natural Gas |  | Fixed price forward sales |  | 269 |  |  | C$2.36 |  | 1/1/2023 |  | 3/31/2023
Canada |  | Natural Gas |  | Fixed price forward sales |  | 250 |  |  | C$2.35 |  | 4/1/2023 |  | 12/31/2023
Canada |  | Natural Gas |  | Fixed price forward sales |  | 162 |  |  | C$2.39 |  | 1/1/2024 |  | 12/31/2024
Canada |  | Natural Gas |  | Fixed price forward sales |  | 45 |  |  | US$2.05 |  | 10/1/2022 |  | 12/31/2022
Canada |  | Natural Gas |  | Fixed price forward sales |  | 25 |  |  | US$1.98 |  | 1/1/2023 |  | 10/31/2024
Canada |  | Natural Gas |  | Fixed price forward sales |  | 15 |  |  | US$1.98 |  | 11/1/2024 |  | 12/31/2024

Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2021 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 36 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at September 30, 2022, covering certain future U.S. crude oil sales volumes for the remainder of 2022. A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately $28.5 million, while a 10% decrease would have decreased the recorded net payable by a similar amount.
There were no derivative foreign exchange contracts in place at September 30, 2022.
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, 2022, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2021 Form 10-K filed on February 25, 2022. The Company has not identified any additional risk factors not previously disclosed in its 2021 Form 10-K report.
ITEM 6. EXHIBITS
The Exhibit Index on page 38 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

| MURPHY OIL CORPORATION
| (Registrant)
| By | /s/ PAUL D. VAUGHAN
|  | Paul D. Vaughan
|  | Vice President and Controller
|  | (Chief Accounting Officer and Duly Authorized Officer)

November 3, 2022
(Date)
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EXHIBIT INDEX
The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.

Exhibit No. |  |  |
*31.1 |  | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
*31.2 |  | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
*32 |  | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
101. INS |  | XBRL Instance Document |
101. SCH |  | XBRL Taxonomy Extension Schema Document |
101. CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document |
101. DEF |  | XBRL Taxonomy Extension Definition Linkbase Document |
101. LAB |  | XBRL Taxonomy Extension Labels Linkbase Document |
101. PRE |  | XBRL Taxonomy Extension Presentation Linkbase |

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