UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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(Mark One) |
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 20212022
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.
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Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 20212022 was 154,434,953155,452,838.
MURPHY OIL CORPORATION
TABLE OF CONTENTS
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)
| (Thousands of dollars) | (Thousands of dollars) | June 30, 2021 | | December 31, 2020 | (Thousands of dollars) | June 30, 2022 | | December 31, 2021 |
ASSETS | ASSETS | | | | ASSETS | | | |
Current assets | Current assets | | Current assets | |
Cash and cash equivalents | Cash and cash equivalents | $ | 418,100 | | | 310,606 | | Cash and cash equivalents | $ | 432,019 | | | 521,184 | |
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020 | 366,542 | | | 262,014 | | |
Accounts receivable, net | | Accounts receivable, net | 522,023 | | | 258,150 | |
Inventories | Inventories | 57,116 | | | 66,076 | | Inventories | 63,886 | | | 54,198 | |
Prepaid expenses | Prepaid expenses | 36,027 | | | 33,860 | | Prepaid expenses | 33,392 | | | 31,925 | |
Assets held for sale | Assets held for sale | 40,821 | | | 327,736 | | Assets held for sale | 15,561 | | | 15,453 | |
Total current assets | Total current assets | 918,606 | | | 1,000,292 | | Total current assets | 1,066,881 | | | 880,910 | |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,146,262 in 2021 and $11,455,305 in 2020 | 8,224,538 | | | 8,269,038 | | |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,751,486 in 2022 and $12,457,851 in 2021 | | Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,751,486 in 2022 and $12,457,851 in 2021 | 8,295,655 | | | 8,127,852 | |
Operating lease assets | Operating lease assets | 973,801 | | | 927,658 | | Operating lease assets | 855,975 | | | 881,389 | |
Deferred income taxes | Deferred income taxes | 457,600 | | | 395,253 | | Deferred income taxes | 326,706 | | | 385,516 | |
Deferred charges and other assets | Deferred charges and other assets | 29,645 | | | 28,611 | | Deferred charges and other assets | 26,994 | | | 29,273 | |
| Total assets | Total assets | $ | 10,604,190 | | | 10,620,852 | | Total assets | $ | 10,572,211 | | | 10,304,940 | |
LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
Current liabilities | Current liabilities | | Current liabilities | |
Current maturities of long-term debt, finance lease | Current maturities of long-term debt, finance lease | $ | 755 | | | 0 | | Current maturities of long-term debt, finance lease | $ | 670 | | | 654 | |
Accounts payable | Accounts payable | 744,067 | | | 407,097 | | Accounts payable | 910,009 | | | 623,129 | |
Income taxes payable | Income taxes payable | 19,176 | | | 18,018 | | Income taxes payable | 25,452 | | | 19,951 | |
Other taxes payable | Other taxes payable | 20,290 | | | 22,498 | | Other taxes payable | 30,698 | | | 20,306 | |
Operating lease liabilities | Operating lease liabilities | 167,474 | | | 103,758 | | Operating lease liabilities | 167,953 | | | 139,427 | |
Other accrued liabilities | Other accrued liabilities | 321,524 | | | 150,578 | | Other accrued liabilities | 483,430 | | | 360,859 | |
Liabilities associated with assets held for sale | 0 | | | 14,372 | | |
| Total current liabilities | Total current liabilities | 1,273,286 | | | 716,321 | | Total current liabilities | 1,618,212 | | | 1,164,326 | |
Long-term debt, including finance lease obligation | Long-term debt, including finance lease obligation | 2,762,851 | | | 2,988,067 | | Long-term debt, including finance lease obligation | 2,267,934 | | | 2,465,414 | |
Asset retirement obligations | Asset retirement obligations | 817,502 | | | 816,308 | | Asset retirement obligations | 863,892 | | | 839,776 | |
Deferred credits and other liabilities | Deferred credits and other liabilities | 738,407 | | | 680,580 | | Deferred credits and other liabilities | 439,404 | | | 570,574 | |
Non-current operating lease liabilities | Non-current operating lease liabilities | 826,713 | | | 845,088 | | Non-current operating lease liabilities | 706,016 | | | 761,162 | |
Deferred income taxes | Deferred income taxes | 143,603 | | | 180,341 | | Deferred income taxes | 188,523 | | | 182,892 | |
| Total liabilities | Total liabilities | 6,562,362 | | | 6,226,705 | | Total liabilities | 6,083,981 | | | 5,984,144 | |
Equity | Equity | | Equity | |
Cumulative Preferred Stock, par $100, authorized 400,000 shares, NaN issued | 0 | | | 0 | | |
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2021 and 195,100,628 shares in 2020 | 195,101 | | | 195,101 | | |
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | | 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 | | 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 | Capital in excess of par value | 915,181 | | | 941,692 | | Capital in excess of par value | 883,368 | | | 926,698 | |
Retained earnings | Retained earnings | 4,980,428 | | | 5,369,538 | | Retained earnings | 5,405,400 | | | 5,218,670 | |
Accumulated other comprehensive loss | Accumulated other comprehensive loss | (553,519) | | | (601,333) | | Accumulated other comprehensive loss | (554,727) | | | (527,711) | |
Treasury stock | Treasury stock | (1,656,591) | | | (1,690,661) | | Treasury stock | (1,616,340) | | | (1,655,447) | |
Murphy Shareholders' Equity | Murphy Shareholders' Equity | 3,880,600 | | | 4,214,337 | | Murphy Shareholders' Equity | 4,312,802 | | | 4,157,311 | |
Noncontrolling interest | Noncontrolling interest | 161,228 | | | 179,810 | | Noncontrolling interest | 175,428 | | | 163,485 | |
Total equity | Total equity | 4,041,828 | | | 4,394,147 | | Total equity | 4,488,230 | | | 4,320,796 | |
Total liabilities and equity | Total liabilities and equity | $ | 10,604,190 | | | 10,620,852 | | Total liabilities and equity | $ | 10,572,211 | | | 10,304,940 | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars, except per share amounts) | (Thousands of dollars, except per share amounts) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars, except per share amounts) | 2022 | | 2021 | | 2022 | | 2021 |
Revenues and other income | Revenues and other income | | | | | | | | Revenues and other income | | | | | | | |
Revenue from sales to customers | $ | 758,829 | | | 285,745 | | $ | 1,351,356 | | | 886,303 | | |
(Loss) gain on crude contracts | (226,245) | | | (75,880) | | | (440,630) | | | 324,792 | | |
Revenue from production | | Revenue from production | $ | 1,146,299 | | | 758,829 | | $ | 1,980,827 | | | 1,351,356 | |
Sales of purchased natural gas | | Sales of purchased natural gas | 49,939 | | | — | | | 86,785 | | | — | |
Total revenue from sales to customers | | Total revenue from sales to customers | 1,196,238 | | | 758,829 | | | 2,067,612 | | | 1,351,356 | |
Loss on crude contracts | | Loss on crude contracts | (103,068) | | | (226,245) | | | (423,845) | | | (440,630) | |
Gain on sale of assets and other income | Gain on sale of assets and other income | 17,059 | | | 1,677 | | | 18,902 | | | 4,175 | | Gain on sale of assets and other income | 7,887 | | | 17,059 | | | 10,251 | | | 18,902 | |
Total revenues and other income | Total revenues and other income | 549,643 | | | 211,542 | | | 929,628 | | | 1,215,270 | | Total revenues and other income | 1,101,057 | | | 549,643 | | | 1,654,018 | | | 929,628 | |
Costs and expenses | Costs and expenses | | | | | | | | Costs and expenses | | | | | | | |
Lease operating expenses | Lease operating expenses | 126,413 | | | 144,644 | | | 273,577 | | | 353,792 | | Lease operating expenses | 147,352 | | | 126,413 | | | 284,177 | | | 273,577 | |
Severance and ad valorem taxes | Severance and ad valorem taxes | 11,314 | | | 6,442 | | | 20,545 | | | 15,864 | | Severance and ad valorem taxes | 17,565 | | | 11,314 | | | 32,200 | | | 20,545 | |
Transportation, gathering and processing | Transportation, gathering and processing | 49,696 | | | 41,090 | | | 92,608 | | | 85,457 | | Transportation, gathering and processing | 49,948 | | | 49,696 | | | 96,871 | | | 92,608 | |
Costs of purchased natural gas | | Costs of purchased natural gas | 47,971 | | | — | | | 81,636 | | | — | |
Exploration expenses, including undeveloped lease amortization | Exploration expenses, including undeveloped lease amortization | 13,543 | | | 29,468 | | | 25,323 | | | 49,594 | | Exploration expenses, including undeveloped lease amortization | 15,151 | | | 13,543 | | | 62,717 | | | 25,323 | |
Selling and general expenses | Selling and general expenses | 29,113 | | | 39,100 | | | 58,616 | | | 75,872 | | Selling and general expenses | 27,130 | | | 29,113 | | | 60,659 | | | 58,616 | |
Restructuring expenses | 0 | | | 41,397 | | | 0 | | | 41,397 | | |
| Depreciation, depletion and amortization | Depreciation, depletion and amortization | 227,288 | | | 231,446 | | | 425,566 | | | 537,548 | | Depreciation, depletion and amortization | 195,856 | | | 227,288 | | | 359,980 | | | 425,566 | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 12,164 | | | 10,469 | | | 22,656 | | | 20,435 | | Accretion of asset retirement obligations | 11,563 | | | 12,164 | | | 23,439 | | | 22,656 | |
Impairment of assets | Impairment of assets | 0 | | | 19,616 | | | 171,296 | | | 987,146 | | Impairment of assets | — | | | — | | | — | | | 171,296 | |
Other expense (benefit) | 70,328 | | | 22,007 | | | 91,407 | | | (23,181) | | |
Other operating expense | | Other operating expense | 36,913 | | | 70,328 | | | 142,855 | | | 91,407 | |
Total costs and expenses | Total costs and expenses | 539,859 | | | 585,679 | | | 1,181,594 | | | 2,143,924 | | Total costs and expenses | 549,449 | | | 539,859 | | | 1,144,534 | | | 1,181,594 | |
Operating income (loss) from continuing operations | Operating income (loss) from continuing operations | 9,784 | | | (374,137) | | | (251,966) | | | (928,654) | | Operating income (loss) from continuing operations | 551,608 | | | 9,784 | | | 509,484 | | | (251,966) | |
Other income (loss) | Other income (loss) | | | | | | | | Other income (loss) | | | | | | | |
Interest income and other (loss) | (4,525) | | | (5,171) | | | (9,866) | | | (4,930) | | |
Other income (expense) | | Other income (expense) | 5,308 | | | (4,525) | | | 2,813 | | | (9,866) | |
Interest expense, net | Interest expense, net | (43,374) | | | (38,598) | | | (131,474) | | | (79,695) | | Interest expense, net | (41,385) | | | (43,374) | | | (78,662) | | | (131,474) | |
Total other loss | (47,899) | | | (43,769) | | | (141,340) | | | (84,625) | | |
Loss from continuing operations before income taxes | (38,115) | | | (417,906) | | | (393,306) | | | (1,013,279) | | |
Income tax benefit | (11,177) | | | (94,773) | | | (99,336) | | | (186,306) | | |
Loss from continuing operations | (26,938) | | | (323,133) | | | (293,970) | | | (826,973) | | |
Total other (loss) | | Total other (loss) | (36,077) | | | (47,899) | | | (75,849) | | | (141,340) | |
Income (loss) from continuing operations before income taxes | | Income (loss) from continuing operations before income taxes | 515,531 | | | (38,115) | | | 433,635 | | | (393,306) | |
Income tax (benefit) expense | | Income tax (benefit) expense | 105,084 | | | (11,177) | | | 88,123 | | | (99,336) | |
Income (loss) from continuing operations | | Income (loss) from continuing operations | 410,447 | | | (26,938) | | | 345,512 | | | (293,970) | |
(Loss) income from discontinued operations, net of income taxes | (Loss) income from discontinued operations, net of income taxes | (102) | | | (1,267) | | | 106 | | | (6,129) | | (Loss) income from discontinued operations, net of income taxes | (943) | | | (102) | | | (1,494) | | | 106 | |
Net loss including noncontrolling interest | (27,040) | | | (324,400) | | | (293,864) | | | (833,102) | | |
Less: Net income (loss) attributable to noncontrolling interest | 36,042 | | | (7,216) | | | 56,656 | | | (99,814) | | |
NET LOSS ATTRIBUTABLE TO MURPHY | $ | (63,082) | | | (317,184) | | | $ | (350,520) | | | (733,288) | | |
LOSS PER COMMON SHARE – BASIC | | | | | | | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | 409,504 | | | (27,040) | | | 344,018 | | | (293,864) | |
Less: Net income attributable to noncontrolling interest | | Less: Net income attributable to noncontrolling interest | 58,947 | | | 36,042 | | | 106,797 | | | 56,656 | |
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | | NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 350,557 | | | (63,082) | | | $ | 237,221 | | | (350,520) | |
INCOME (LOSS) PER COMMON SHARE – BASIC | | INCOME (LOSS) PER COMMON SHARE – BASIC | | | | | | | |
Continuing operations | Continuing operations | $ | (0.41) | | | (2.05) | | | $ | (2.27) | | | (4.74) | | Continuing operations | $ | 2.27 | | | (0.41) | | | $ | 1.54 | | | (2.27) | |
Discontinued operations | Discontinued operations | 0 | | | (0.01) | | | 0 | | | (0.04) | | Discontinued operations | (0.01) | | | — | | | (0.01) | | | — | |
Net loss | $ | (0.41) | | | (2.06) | | | $ | (2.27) | | | (4.78) | | |
LOSS PER COMMON SHARE – DILUTED | | | | | | | | |
Net income (loss) | | Net income (loss) | $ | 2.26 | | | (0.41) | | | $ | 1.53 | | | (2.27) | |
INCOME (LOSS) PER COMMON SHARE – DILUTED | | INCOME (LOSS) PER COMMON SHARE – DILUTED | | | | | | | |
Continuing operations | Continuing operations | $ | (0.41) | | | (2.05) | | | $ | (2.27) | | | (4.74) | | Continuing operations | $ | 2.24 | | | (0.41) | | | $ | 1.51 | | | (2.27) | |
Discontinued operations | Discontinued operations | 0 | | | (0.01) | | | 0 | | | (0.04) | | Discontinued operations | (0.01) | | | — | | | (0.01) | | | — | |
Net loss | $ | (0.41) | | | (2.06) | | | $ | (2.27) | | | (4.78) | | |
Net income (loss) | | Net income (loss) | $ | 2.23 | | | (0.41) | | | $ | 1.50 | | | (2.27) | |
Cash dividends per Common share | Cash dividends per Common share | 0.125 | | | 0.125 | | | 0.250 | | | 0.375 | | Cash dividends per Common share | $ | 0.175 | | | 0.125 | | | 0.325 | | | 0.250 | |
| Average Common shares outstanding (thousands) | Average Common shares outstanding (thousands) | | Average Common shares outstanding (thousands) | |
Basic | Basic | 154,395 | | | 153,581 | | | 154,153 | | | 153,429 | | Basic | 155,389 | | | 154,395 | | | 155,121 | | | 154,153 | |
Diluted | Diluted | 154,395 | | | 153,581 | | | 154,153 | | | 153,429 | | Diluted | 157,455 | | | 154,395 | | | 157,852 | | | 154,153 | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Net (loss) including noncontrolling interest | $ | (27,040) | | | (324,400) | | | $ | (293,864) | | | (833,102) | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | 409,504 | | | (27,040) | | | $ | 344,018 | | | (293,864) | |
Other comprehensive (loss) income, net of tax | Other comprehensive (loss) income, net of tax | | Other comprehensive (loss) income, net of tax | |
Net (loss) gain from foreign currency translation | Net (loss) gain from foreign currency translation | 17,945 | | | 50,568 | | | 37,842 | | | (67,843) | | Net (loss) gain from foreign currency translation | (51,545) | | | 17,945 | | | (33,525) | | | 37,842 | |
Retirement and postretirement benefit plans | Retirement and postretirement benefit plans | 4,146 | | | (39,234) | | | 8,282 | | | (48,945) | | Retirement and postretirement benefit plans | 3,173 | | | 4,146 | | | 6,509 | | | 8,282 | |
Deferred loss on interest rate hedges reclassified to interest expense | Deferred loss on interest rate hedges reclassified to interest expense | 0 | | | 309 | | | 1,690 | | | 608 | | Deferred loss on interest rate hedges reclassified to interest expense | — | | | — | | | — | | | 1,690 | |
| Other comprehensive (loss) income | Other comprehensive (loss) income | 22,091 | | | 11,643 | | | 47,814 | | | (116,180) | | Other comprehensive (loss) income | (48,372) | | | 22,091 | | | (27,016) | | | 47,814 | |
COMPREHENSIVE (LOSS) | $ | (4,949) | | | (312,757) | | | $ | (246,050) | | | (949,282) | | |
Comprehensive income (loss) including noncontrolling interest | | Comprehensive income (loss) including noncontrolling interest | $ | 361,132 | | | (4,949) | | | 317,002 | | | (246,050) | |
Less: Comprehensive income attributable to noncontrolling interest | | Less: Comprehensive income attributable to noncontrolling interest | 58,947 | | | 36,042 | | | 106,797 | | | 56,656 | |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY | | COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 302,185 | | | (40,991) | | | $ | 210,205 | | | (302,706) | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 |
Operating Activities | Operating Activities | | | | Operating Activities | | | |
Net (loss) including noncontrolling interest | $ | (293,864) | | | (833,102) | | |
Adjustments to reconcile net loss to net cash provided (required) by continuing operations activities | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | 344,018 | | | (293,864) | |
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities | | Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities | |
Loss (income) from discontinued operations | Loss (income) from discontinued operations | (106) | | | 6,129 | | Loss (income) from discontinued operations | 1,494 | | | (106) | |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | 425,566 | | | 537,548 | | Depreciation, depletion and amortization | 359,980 | | | 425,566 | |
Previously suspended exploration costs | 633 | | | 7,677 | | |
Unsuccessful exploration well costs and previously suspended exploration costs | | Unsuccessful exploration well costs and previously suspended exploration costs | 34,102 | | | 633 | |
Amortization of undeveloped leases | Amortization of undeveloped leases | 8,882 | | | 14,770 | | Amortization of undeveloped leases | 7,980 | | | 8,882 | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 22,656 | | | 20,435 | | Accretion of asset retirement obligations | 23,439 | | | 22,656 | |
Deferred income tax (benefit) expense | | Deferred income tax (benefit) expense | 66,691 | | | (101,195) | |
Mark to market loss on contingent consideration | | Mark to market loss on contingent consideration | 129,818 | | | 76,677 | |
Mark to market loss on crude contracts | | Mark to market loss on crude contracts | 100,343 | | | 284,360 | |
Long-term non-cash compensation | | Long-term non-cash compensation | 40,467 | | | 25,318 | |
Impairment of assets | Impairment of assets | 171,296 | | | 987,146 | | Impairment of assets | — | | | 171,296 | |
Noncash restructuring expense | 0 | | | 17,565 | | |
Deferred income tax benefit | (101,195) | | | (167,902) | | |
| Mark to market loss (gain) on contingent consideration | 76,677 | | | (43,529) | | |
Mark to market loss (gain) on crude contracts | 284,360 | | | (173,848) | | |
Long-term non-cash compensation | 25,318 | | | 22,760 | | |
(Gain) from sale of assets | | (Gain) from sale of assets | (35) | | | — | |
Net (increase) decrease in noncash working capital | Net (increase) decrease in noncash working capital | 26,565 | | | 1,335 | | Net (increase) decrease in noncash working capital | (121,598) | | | 26,565 | |
Other operating activities, net | Other operating activities, net | 39,494 | | | (27,605) | | Other operating activities, net | (27,458) | | | 39,494 | |
Net cash provided by continuing operations activities | Net cash provided by continuing operations activities | 686,282 | | | 369,379 | | Net cash provided by continuing operations activities | 959,241 | | | 686,282 | |
Investing Activities | Investing Activities | | Investing Activities | | | |
Property additions and dry hole costs | (445,314) | | | (537,601) | | |
Property additions and dry hole costs 1 | | Property additions and dry hole costs 1 | (552,825) | | | (422,841) | |
Acquisition of oil and gas properties 1 | | Acquisition of oil and gas properties 1 | (46,491) | | | (22,473) | |
Property additions for King's Quay FPS | Property additions for King's Quay FPS | (17,734) | | | (51,635) | | Property additions for King's Quay FPS | — | | | (17,734) | |
| Proceeds from sales of property, plant and equipment | Proceeds from sales of property, plant and equipment | 269,363 | | | 0 | | Proceeds from sales of property, plant and equipment | 47 | | | 269,363 | |
Net cash (required) by investing activities | Net cash (required) by investing activities | (193,685) | | | (589,236) | | Net cash (required) by investing activities | (599,269) | | | (193,685) | |
Financing Activities | Financing Activities | | Financing Activities | | | |
Borrowings on revolving credit facility | Borrowings on revolving credit facility | 165,000 | | | 370,000 | | Borrowings on revolving credit facility | 100,000 | | | 165,000 | |
Repayment of revolving credit facility | Repayment of revolving credit facility | (365,000) | | | (200,000) | | Repayment of revolving credit facility | (100,000) | | | (365,000) | |
Retirement of debt | Retirement of debt | (576,358) | | | (12,225) | | Retirement of debt | (200,000) | | | (576,358) | |
Debt issuance, net of cost | Debt issuance, net of cost | 541,974 | | | (613) | | Debt issuance, net of cost | — | | | 541,974 | |
Early redemption of debt cost | Early redemption of debt cost | (34,177) | | | 0 | | Early redemption of debt cost | (3,438) | | | (34,177) | |
Distributions to noncontrolling interest | Distributions to noncontrolling interest | (75,238) | | | (32,400) | | Distributions to noncontrolling interest | (94,854) | | | (75,238) | |
Contingent consideration payment | | Contingent consideration payment | (81,742) | | | — | |
Cash dividends paid | Cash dividends paid | (38,590) | | | (57,590) | | Cash dividends paid | (50,491) | | | (38,590) | |
Withholding tax on stock-based incentive awards | Withholding tax on stock-based incentive awards | (3,895) | | | (7,247) | | Withholding tax on stock-based incentive awards | (16,697) | | | (3,895) | |
Proceeds from term loan and other loans | 0 | | | 371 | | |
Capital lease obligation payments | Capital lease obligation payments | (371) | | | (336) | | Capital lease obligation payments | (320) | | | (371) | |
| Net cash (required) provided by financing activities | (386,655) | | | 59,960 | | |
Cash Flows from Discontinued Operations 1 | | |
Operating activities | 0 | | | (1,202) | | |
Investing activities | 0 | | | 4,494 | | |
Financing activities | 0 | | | 0 | | |
Net cash provided by discontinued operations | 0 | | | 3,292 | | |
| Net cash (required) by financing activities | | Net cash (required) by financing activities | (447,542) | | | (386,655) | |
| | Effect of exchange rate changes on cash and cash equivalents | Effect of exchange rate changes on cash and cash equivalents | 1,552 | | | (1,358) | | Effect of exchange rate changes on cash and cash equivalents | (1,595) | | | 1,552 | |
Net increase (decrease) in cash and cash equivalents | 107,494 | | | (161,255) | | |
Net (decrease) increase in cash and cash equivalents | | Net (decrease) increase in cash and cash equivalents | (89,165) | | | 107,494 | |
Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | 310,606 | | | 306,760 | | Cash and cash equivalents at beginning of period | 521,184 | | | 310,606 | |
Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | $ | 418,100 | | | 145,505 | | Cash and cash equivalents at end of period | $ | 432,019 | | | 418,100 | |
1 Net cash provided by discontinued operations is not part ofCertain prior-period amounts have been reclassified to conform to the cash flow reconciliation. current period presentation.
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Cumulative Preferred Stock – par $100, authorized 400,000 shares, NaN issued | $ | 0 | | | 0 | | | $ | 0 | | | 0 | | |
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2021 and 195,100,628 shares at June 30, 2020 | | | | | | | | |
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued | | Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued | $ | — | | | — | | | $ | — | | | — | |
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2022 and 195,100,628 shares at June 30, 2021 | | Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2022 and 195,100,628 shares at June 30, 2021 | | | | | | | |
Balance at beginning of period | Balance at beginning of period | 195,101 | | | 195,101 | | | 195,101 | | | 195,089 | | Balance at beginning of period | 195,101 | | | 195,101 | | | 195,101 | | | 195,101 | |
Exercise of stock options | Exercise of stock options | — | | | — | | | — | | | 12 | | Exercise of stock options | — | | | — | | | — | | | — | |
Balance at end of period | Balance at end of period | 195,101 | | | 195,101 | | | 195,101 | | | 195,101 | | Balance at end of period | 195,101 | | | 195,101 | | | 195,101 | | | 195,101 | |
Capital in Excess of Par Value | Capital in Excess of Par Value | | | | | | | | Capital in Excess of Par Value | | | | | | | |
Balance at beginning of period | Balance at beginning of period | 914,303 | | | 924,930 | | | 941,692 | | | 949,445 | | Balance at beginning of period | 880,537 | | | 914,303 | | | 926,698 | | | 941,692 | |
Exercise of stock options, including income tax benefits | Exercise of stock options, including income tax benefits | (587) | | | — | | | (626) | | | (156) | | Exercise of stock options, including income tax benefits | (3,415) | | | (587) | | | (10,635) | | | (626) | |
Restricted stock transactions and other | Restricted stock transactions and other | (5,347) | | | (636) | | | (38,347) | | | (33,240) | | Restricted stock transactions and other | — | | | (5,347) | | | (45,169) | | | (38,347) | |
Share-based compensation | Share-based compensation | 6,812 | | | 7,135 | | | 12,462 | | | 15,380 | | Share-based compensation | 6,246 | | | 6,812 | | | 12,474 | | | 12,462 | |
| Balance at end of period | Balance at end of period | 915,181 | | | 931,429 | | | 915,181 | | | 931,429 | | Balance at end of period | 883,368 | | | 915,181 | | | 883,368 | | | 915,181 | |
Retained Earnings | Retained Earnings | | | | | | | | Retained Earnings | | | | | | | |
Balance at beginning of period | Balance at beginning of period | 5,062,813 | | | 6,159,808 | | | 5,369,538 | | | 6,614,304 | | Balance at beginning of period | 5,082,034 | | | 5,062,813 | | | 5,218,670 | | | 5,369,538 | |
Net (loss) attributable to Murphy | (63,082) | | | (317,184) | | | (350,520) | | | (733,288) | | |
Net income (loss) attributable to Murphy | | Net income (loss) attributable to Murphy | 350,557 | | | (63,082) | | | 237,221 | | | (350,520) | |
| Cash dividends | (19,303) | | | (19,198) | | | (38,590) | | | (57,590) | | |
Cash dividends paid | | Cash dividends paid | (27,191) | | | (19,303) | | | (50,491) | | | (38,590) | |
Balance at end of period | Balance at end of period | 4,980,428 | | | 5,823,426 | | | 4,980,428 | | | 5,823,426 | | Balance at end of period | 5,405,400 | | | 4,980,428 | | | 5,405,400 | | | 4,980,428 | |
Accumulated Other Comprehensive Loss | Accumulated Other Comprehensive Loss | | | | | | | | Accumulated Other Comprehensive Loss | | | | | | | |
Balance at beginning of period | Balance at beginning of period | (575,610) | | | (701,984) | | | (601,333) | | | (574,161) | | Balance at beginning of period | (506,355) | | | (575,610) | | | (527,711) | | | (601,333) | |
Foreign currency translation gain (loss), net of income taxes | 17,945 | | | 50,568 | | | 37,842 | | | (67,843) | | |
Foreign currency translation (loss) gain, net of income taxes | | Foreign currency translation (loss) gain, net of income taxes | (51,545) | | | 17,945 | | | (33,525) | | | 37,842 | |
Retirement and postretirement benefit plans, net of income taxes | Retirement and postretirement benefit plans, net of income taxes | 4,146 | | | (39,234) | | | 8,282 | | | (48,945) | | Retirement and postretirement benefit plans, net of income taxes | 3,173 | | | 4,146 | | | 6,509 | | | 8,282 | |
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | — | | | 309 | | | 1,690 | | | 608 | | Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | — | | | — | | | — | | | 1,690 | |
| Balance at end of period | Balance at end of period | (553,519) | | | (690,341) | | | (553,519) | | | (690,341) | | Balance at end of period | (554,727) | | | (553,519) | | | (554,727) | | | (553,519) | |
Treasury Stock | Treasury Stock | | | | | | | | Treasury Stock | | | | | | | |
Balance at beginning of period | Balance at beginning of period | (1,661,416) | | | (1,691,706) | | | (1,690,661) | | | (1,717,217) | | Balance at beginning of period | (1,618,478) | | | (1,661,416) | | | (1,655,447) | | | (1,690,661) | |
| Awarded restricted stock, net of forfeitures | Awarded restricted stock, net of forfeitures | 4,339 | | | 636 | | | 33,545 | | | 26,147 | | Awarded restricted stock, net of forfeitures | — | | | 4,339 | | | 32,297 | | | 33,545 | |
Exercise of stock options | Exercise of stock options | 486 | | | — | | | 525 | | | — | | Exercise of stock options | 2,138 | | | 486 | | | 6,810 | | | 525 | |
Balance at end of period – 40,665,675 shares of Common Stock in 2021 and 41,512,066 shares of Common Stock in 2020, at cost | (1,656,591) | | | (1,691,070) | | | (1,656,591) | | | (1,691,070) | | |
Balance at end of period – 39,677,584 shares of Common Stock in 2022 and 40,665,675 shares of Common Stock in 2021, at cost | | Balance at end of period – 39,677,584 shares of Common Stock in 2022 and 40,665,675 shares of Common Stock in 2021, at cost | (1,616,340) | | | (1,656,591) | | | (1,616,340) | | | (1,656,591) | |
Murphy Shareholders’ Equity | Murphy Shareholders’ Equity | 3,880,600 | | | 4,568,545 | | | 3,880,600 | | | 4,568,545 | | Murphy Shareholders’ Equity | 4,312,802 | | | 3,880,600 | | | 4,312,802 | | | 3,880,600 | |
Noncontrolling Interest | Noncontrolling Interest | | Noncontrolling Interest | |
Balance at beginning of period | Balance at beginning of period | 164,418 | | | 212,154 | | | 179,810 | | | 337,151 | | Balance at beginning of period | 171,451 | | | 164,418 | | | 163,485 | | | 179,810 | |
| Net income (loss) attributable to noncontrolling interest | 36,042 | | | (7,216) | | | 56,656 | | | (99,814) | | |
Net income attributable to noncontrolling interest | | Net income attributable to noncontrolling interest | 58,947 | | | 36,042 | | | 106,797 | | | 56,656 | |
Distributions to noncontrolling interest owners | Distributions to noncontrolling interest owners | (39,232) | | | (1) | | | (75,238) | | | (32,400) | | Distributions to noncontrolling interest owners | (54,970) | | | (39,232) | | | (94,854) | | | (75,238) | |
Balance at end of period | Balance at end of period | 161,228 | | | 204,937 | | | 161,228 | | | 204,937 | | Balance at end of period | 175,428 | | | 161,228 | | | 175,428 | | | 161,228 | |
Total Equity | Total Equity | $ | 4,041,828 | | | 4,773,482 | | | $ | 4,041,828 | | | 4,773,482 | | Total Equity | $ | 4,488,230 | | | 4,041,828 | | | $ | 4,488,230 | | | 4,041,828 | |
See Notes to Consolidated Financial Statements, page 7.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company)(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 2 variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2021,2022, our maximum exposure to loss was $3.4$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 June 30, 20212022 and December 31, 2020,2021, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 20212022 and 2020,2021, 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 20202021 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 20212022, are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Income Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. The Company adopted this guidance in the first quarter of 2021 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
None affecting the Company.
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 2 key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from 3 primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.
U.S. - In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the Offshoreoffshore 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Disaggregation of Revenue
The Company reviews performance based on 2 key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-month and six-month periodsperiod ended June 30, 2022, and 2021, the Company recognized $758.8$1,196 million and $1,351.4$758.8 million, respectively, from contracts withtotal revenue from sales to customers, for the sales of oil, natural gas liquids and natural gas. For the three-month and six-month periods ended June 30, 2020, the Company recognized $285.7 million and $886.3 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
Net crude oil and condensate revenue | | | | | | | |
United States | Onshore | $ | 183,267 | | | 54,550 | | | 297,757 | | | 185,786 | |
| Offshore | 411,076 | | | 150,253 | | | 739,417 | | | 497,225 | |
Canada | Onshore | 30,695 | | | 11,527 | | | 60,598 | | | 34,910 | |
| Offshore | 31,772 | | | 11,077 | | | 49,834 | | | 35,691 | |
Other | | 0 | | | (58) | | | 0 | | | 1,806 | |
Total crude oil and condensate revenue | 656,810 | | | 227,349 | | | 1,147,606 | | | 755,418 | |
| | | | | | | | |
Net natural gas liquids revenue | | | | | | | |
United States | Onshore | 9,596 | | | 3,876 | | | 17,124 | | | 9,379 | |
| Offshore | 10,766 | | | 3,464 | | | 20,820 | | | 8,490 | |
Canada | Onshore | 3,240 | | | 1,276 | | | 7,227 | | | 3,310 | |
Total natural gas liquids revenue | 23,602 | | | 8,616 | | | 45,171 | | | 21,179 | |
| | | | | | | | |
Net natural gas revenue | | | | | | | |
United States | Onshore | 6,872 | | | 4,090 | | | 13,315 | | | 9,648 | |
| Offshore | 17,273 | | | 10,665 | | | 39,411 | | | 25,660 | |
Canada | Onshore | 54,272 | | | 35,025 | | | 105,853 | | | 74,398 | |
Total natural gas revenue | 78,417 | | | 49,780 | | | 158,579 | | | 109,706 | |
Total revenue from contracts with customers | 758,829 | | | 285,745 | | | 1,351,356 | | | 886,303 | |
| | | | | | | | |
(Loss) gain on crude contracts | (226,245) | | | (75,880) | | | (440,630) | | | 324,792 | |
Gain on sale of assets and other income | 17,059 | | | 1,677 | | | 18,902 | | | 4,175 | |
Total revenue and other income | $ | 549,643 | | | 211,542 | | | 929,628 | | | 1,215,270 | |
For the six-month period ended June 30, 2022, and 2021, the Company recognized $2,067.6 million and $1,351.4 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | | 2022 | | 2021 | | 2022 | | 2021 |
Net crude oil and condensate revenue | | | | | | | |
United States | Onshore | $ | 264,841 | | | 183,267 | | | $ | 436,537 | | | 297,757 | |
| Offshore | 612,526 | | | 411,076 | | | 1,078,147 | | | 739,417 | |
Canada | Onshore | 40,417 | | | 30,695 | | | 77,114 | | | 60,598 | |
| Offshore | 38,354 | | | 31,772 | | | 67,186 | | | 49,834 | |
Other | | 13,636 | | | — | | | 13,636 | | | — | |
Total crude oil and condensate revenue | 969,774 | | | 656,810 | | | 1,672,620 | | | 1,147,606 | |
| | | | | | | | |
Net natural gas liquids revenue | | | | | | | |
United States | Onshore | 18,062 | | | 9,596 | | | 34,747 | | | 17,124 | |
| Offshore | 18,093 | | | 10,766 | | | 32,072 | | | 20,820 | |
Canada | Onshore | 5,001 | | | 3,240 | | | 9,868 | | | 7,227 | |
Total natural gas liquids revenue | 41,156 | | | 23,602 | | | 76,687 | | | 45,171 | |
| | | | | | | | |
Net natural gas revenue | | | | | | | |
United States | Onshore | 19,034 | | | 6,872 | | | 30,403 | | | 13,315 | |
| Offshore | 43,567 | | | 17,273 | | | 69,768 | | | 39,411 | |
Canada | Onshore | 72,768 | | | 54,272 | | | 131,349 | | | 105,853 | |
Total natural gas revenue | 135,369 | | | 78,417 | | | 231,520 | | | 158,579 | |
| | | | | | | | |
Revenue from production | 1,146,299 | | | 758,829 | | | 1,980,827 | | | 1,351,356 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Sales of purchased natural gas | | | | | | | |
United States | Offshore | 181 | | | — | | | 181 | | | — | |
Canada | Onshore | 49,758 | | | — | | | 86,604 | | | — | |
Total sales of purchased natural gas | 49,939 | | | — | | | 86,785 | | | — | |
| | | | | | | |
Total revenue from sales to customers | 1,196,238 | | | 758,829 | | | 2,067,612 | | | 1,351,356 | |
| | | | | | | | |
Loss on crude contracts | (103,068) | | | (226,245) | | | (423,845) | | | (440,630) | |
Gain on sale of assets and other income | 7,887 | | | 17,059 | | | 10,251 | | | 18,902 | |
Total revenues and other income | $ | 1,101,057 | | | 549,643 | | | $ | 1,654,018 | | | 929,628 | |
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 June 30, 2021,2022, and December 31, 2020,2021, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $206.6$292.4 million and $135.2$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
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 atof June 30, 2021.2022.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers(Contd.)
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’sCompany’s long-term strategy.
As of June 30, 2021,2022, 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 June 30, 20212022 |
Location | | Commodity | | End Date | | Description | | Approximate Volumes |
| | | |
U.S. | | Oil | | Q4 2021 | | Fixed quantity delivery in Eagle Ford | | 17,000 BOED |
U.S. | | Natural Gas and NGL | | Q1Q2 2023 | | Deliveries from dedicated acreage in Eagle Ford | | As produced |
Canada | | Natural Gas | | Q4 2021 | | Contracts to sell natural gas at USD index pricing | | 10 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at USD index pricing | | 8 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at CAD fixed prices | | 5 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at USD fixed pricing | | 20 MMCFD |
Canada | | Natural Gas | | Q4 2023 | 1 | Contracts to sell natural gas at USD index pricing | | 25 MMCFD |
Canada | | Natural Gas | | Q4 2023 | 1 | 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 | 1 | 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 | 1 | Contracts to sell natural gas at USD index pricing | | 49 MMCFD |
Canada | | NGL | | Q3 2023 | | Contracts to sell natural gas liquids at various CAD pricing | | 952 BOED |
1 These contracts are scheduled to commence after the balance sheet date, at various dates between Q4 2021 and Q1 2022.Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of June 30, 2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $197.5 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2021 and 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)
| | | | | | | | | | | |
(Thousands of dollars) | 2021 | | 2020 |
Beginning balance at January 1 | $ | 181,616 | | | 217,326 | |
Additions pending the determination of proved reserves | 15,921 | | | 2,328 | |
| | | |
Capitalized exploratory well costs charged to expense | 0 | | | (39,519) | |
Balance at June 30 | $ | 197,537 | | | 180,135 | |
As of June 30, 2022, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $178.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 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 | 9,412 | | | 15,921 | |
| | | |
Capitalized exploratory well costs charged to expense | (10,472) | | | — | |
Balance at June 30 | $ | 178,421 | | | 197,537 | |
The capitalized well costs charged to expense during 20202022 represent a charge for asset impairments (see below).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.
| | | June 30, | | June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| (Thousands of dollars) | (Thousands of dollars) | Amount | | No. of Wells | | No. of Projects | | Amount | | No. of Wells | | No. of Projects | (Thousands of dollars) | Amount | | No. of Wells | | No. of Projects | | Amount | | No. of Wells | | No. of Projects |
Aging of capitalized well costs: | Aging of capitalized well costs: | | | | | | | | | | | | Aging of capitalized well costs: | | | | | | | | | | | |
Zero to one year | Zero to one year | $ | 13,881 | | | 3 | | | 3 | | | 24,429 | | | 3 | | | 3 | | Zero to one year | $ | 4,268 | | | 2 | | | 2 | | | 13,881 | | | 3 | | | 3 | |
One to two years | One to two years | 23,811 | | | 3 | | | 3 | | | 30,691 | | | 2 | | | 2 | | One to two years | 2,813 | | | 2 | | | 2 | | | 23,811 | | | 3 | | | 3 | |
Two to three years | Two to three years | 30,562 | | | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | Two to three years | 26,848 | | | 3 | | | 2 | | | 30,562 | | | 2 | | | 2 | |
Three years or more | Three years or more | 129,283 | | | 6 | | | 0 | | | 125,015 | | | 6 | | | 0 | | Three years or more | 144,492 | | | 8 | | | 2 | | | 129,283 | | | 6 | | | — | |
| | $ | 197,537 | | | 14 | | | 8 | | | 180,135 | | | 11 | | | 5 | | | $ | 178,421 | | | 15 | | | 8 | | | 197,537 | | | 14 | | | 8 | |
Of the $183.6$174.2 million of exploratory well costs capitalized more than one year at June 30, 2021, $91.52022, $94.7 million is in Vietnam, $46.2$48.5 million is in the U.S., $25.7$15.5 million is in Brunei, $15.4Mexico, $10.6 million is in Mexico,Brunei, and $4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Impairments
DuringThere were no impairments in the first six 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 the partners, of operating and production plans.
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand from the COVID-19 pandemic) led to impairments in certainplans at end of the Company’s U.S. Offshorefirst quarter 2021. Later in 2021, the Company sanctioned an asset life extension project and Other Foreign properties. The Company recorded pretax noncash impairment chargesacquired an additional 7.525% working interest at Terra Nova following a commercial agreement to extend the life of $987.1 million to reduce the carrying values to their estimated fair values at select properties.field.
The fair valuesDivestments
There were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participantsno divestments in the applicable region.
The following table reflects the recognized impairments for thefirst six months ended June 30, 2021 and 2020.
| | | | | | | | | | | |
| Six Months Ended June 30, |
(Thousands of dollars) | 2021 | | 2020 |
U.S. | $ | 0 | | | 947,437 | |
Canada | 171,296 | | | 0 | |
Other Foreign | 0 | | | 39,709 | |
| | | |
| $ | 171,296 | | | 987,146 | |
Divestments
of 2022. 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 reimbursesreimbursed the Company for previously incurred capital expenditures.
Acquisitions
In June 2022, the Company acquired an additional working interest of 11.0% in the Kodiak field for a purchase price of $46.5 million, net of post-closing adjustments.
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 post-closing adjustments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note E – Assets Held for Sale and Discontinued Operations
The Company has accounted for its former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and six-month periods ended June 30, 20212022 and 20202021 were as follows:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Revenues | Revenues | $ | 246 | | | 1 | | | $ | 658 | | | 4,074 | | Revenues | $ | — | | | 246 | | | $ | 10 | | | 658 | |
Costs and expenses | Costs and expenses | | Costs and expenses | |
| Other costs and expenses (benefits) | Other costs and expenses (benefits) | 348 | | | 1,268 | | | 552 | | | 10,203 | | Other costs and expenses (benefits) | 943 | | | 348 | | | 1,504 | | | 552 | |
(Loss) income before taxes | (Loss) income before taxes | (102) | | | (1,267) | | | 106 | | | (6,129) | | (Loss) income before taxes | (943) | | | (102) | | | (1,494) | | | 106 | |
Income tax expense | Income tax expense | 0 | | | 0 | | | 0 | | | 0 | | Income tax expense | — | | | — | | | — | | | — | |
(Loss) income from discontinued operations | (Loss) income from discontinued operations | $ | (102) | | | (1,267) | | | $ | 106 | | | (6,129) | | (Loss) income from discontinued operations | $ | (943) | | | (102) | | | $ | (1,494) | | | 106 | |
As of June 30, 2022 and December 31, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the net property, plant and equipment of the CA-2 project in Brunei and the Company’s office building in El Dorado, Arkansas. As of June 30, 2021, the CA-1 asset in Brunei is no longer being marketed for sale.
As of December 31, 2020, assets held for sale included the King’s Quay Floating Production System (FPS) of $250.1 million (sold in March 2021), the Brunei exploration and production properties, and the Company’sformer headquarters office building in El Dorado, Arkansas.
| | | | | | | | | | | |
(Thousands of dollars) | June 30, 2021 | | December 31, 2020 |
Current assets | | | |
Cash | $ | 0 | | | 10,185 | |
| | | |
Inventories | 0 | | | 406 | |
| | | |
Property, plant, and equipment, net | 40,820 | | | 307,704 | |
Deferred income taxes and other assets | — | | | 9,441 | |
| | | |
Total current assets associated with assets held for sale | $ | 40,820 | | | 327,736 | |
| | | |
| | | |
| | | |
| | | |
| | | |
Current liabilities | | | |
Accounts payable | $ | 0 | | | 5,306 | |
Other accrued liabilities | 0 | | | 45 | |
Current maturities of long-term debt (finance lease) | 0 | | | 737 | |
Taxes payable | 0 | | | 1,510 | |
| | | |
Long-term debt (finance lease) | 0 | | | 6,513 | |
Asset retirement obligation | 0 | | | 261 | |
Total current liabilities associated with assets held for sale | $ | 0 | | | 14,372 | |
| | | |
| | | |
| | | |
| | | |
| | | | | | | | | | | |
(Thousands of dollars) | June 30, 2022 | | December 31, 2021 |
Current assets | | | |
| | | |
| | | |
| | | |
| | | |
Property, plant, and equipment, net | 15,561 | | | 15,453 | |
| | | |
| | | |
Total current assets associated with assets held for sale | $ | 15,561 | | | 15,453 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
Note F – Financing Arrangements and Debt
As of June 30, 2021,2022, 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 June 30, 2021,2022, the Company had 0no outstanding borrowings under the RCF and $31.0$27.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2021,2022, the interest rate in effect on borrowings under the facility was 1.78%3.46%. At June 30, 2022 and 2021, the Company was in compliance with all covenants related to the RCF.
On June 2, 2022, the Company redeemed $200.0 million aggregate principal amount of its 6.875% senior notes due 2024 (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 three months and six months ended June 30, 2022. The cash costs of $3.4 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the six months ended June 30, 2022.
In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.0$8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)
(2022; collectively the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the three months and six months ended June 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the six months ended June 30, 2021.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2021.15, 2024.
Subsequent to quarter end,On July 20, 2022, the Company issued a notice of partial redemption with respect to $150.0all of its outstanding, $42.4 million aggregate principal amount, of its 6.875% senior notes due 2024 (2024 Notes). 2024.The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to, but not including, the date of redemption. The redemption date of the 2024 Notes will be August 16, 2021.19, 2022.
On August 1, 2022, the Company announced the commencement of cash tender offers (the “Tender Offers”) to purchase up to $200.0 million in aggregate purchase price of its outstanding 5.750% senior notes due 2025, 6.375% senior notes due 2028 and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)
5.875% senior notes due 2027. Details of the Tender Offers can be found as part of the Company’s Form 8-K filed on August 1, 2022.
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
| | | | | | | | | | | |
| Six Months Ended June 30, |
(Thousands of dollars) | 2021 | | 2020 |
Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | | | |
(Increase) decrease in accounts receivable ¹ | $ | (104,775) | | | 227,710 | |
Decrease in inventories | 8,938 | | | 13,968 | |
(Increase) in prepaid expenses | (1,945) | | | (20,712) | |
Increase (decrease) in accounts payable and accrued liabilities ¹ | 124,699 | | | (219,228) | |
(Decrease) in income taxes payable | (352) | | | (403) | |
Net decrease in noncash operating working capital | $ | 26,565 | | | 1,335 | |
Supplementary disclosures: | | | |
Cash income taxes paid, net of refunds | $ | 1,474 | | | (7) | |
Interest paid, net of amounts capitalized of $7.4 million in 2021 and $4.9 million in 2020 | 80,546 | | | 100,745 | |
| | | |
Non-cash investing activities: | | | |
Asset retirement costs capitalized ² | $ | 6,669 | | | 6,342 | |
Decrease in capital expenditure accrual | 20,614 | | | 58,602 | |
| | | | | | | | | | | |
| Six Months Ended June 30, |
(Thousands of dollars) | 2022 | | 2021 |
Net decrease (increase) in operating working capital, excluding cash and cash equivalents: | | | |
(Increase) in accounts receivable ¹ | $ | (263,104) | | | (104,775) | |
(Increase) decrease in inventories | (10,092) | | | 8,938 | |
(Increase) in prepaid expenses | (1,693) | | | (1,945) | |
Increase in accounts payable and accrued liabilities ¹ | 147,790 | | | 124,699 | |
Increase (decrease) in income taxes payable | 5,501 | | | (352) | |
Net decrease (increase) in noncash operating working capital | $ | (121,598) | | | 26,565 | |
Supplementary disclosures: | | | |
Cash income taxes paid, net of refunds | $ | 1,783 | | | 1,474 | |
Interest paid, net of amounts capitalized of $10.4 million in 2022 and $7.4 million in 2021 | 78,747 | | | 80,546 | |
| | | |
Non-cash investing activities: | | | |
Asset retirement costs capitalized 2 | $ | 9,007 | | | 6,669 | |
(Increase) decrease in capital expenditure accrual | (1,929) | | | 20,614 | |
1 Excludes receivable/payable balances relating to mark-to-market of crude contractsderivative instruments and contingent consideration relating to acquisitions.
2 2021 Excludes non-cash capitalized cost offset by Terra Nova impairment of $74.4 million related to Terra Nova in 2021.million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 20212022 and 2020.2021.
| | | Three Months Ended June 30, | | Three Months Ended June 30, |
| | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Service cost | Service cost | $ | 1,768 | | | 2,166 | | | 327 | | | 446 | | Service cost | $ | 2,129 | | | 1,768 | | | 292 | | | 327 | |
Interest cost | Interest cost | 4,300 | | | 5,763 | | | 521 | | | 794 | | Interest cost | 5,139 | | | 4,300 | | | 574 | | | 521 | |
Expected return on plan assets | Expected return on plan assets | (6,155) | | | (6,297) | | | 0 | | | 0 | | Expected return on plan assets | (7,954) | | | (6,155) | | | — | | | — | |
Amortization of prior service cost (credit) | Amortization of prior service cost (credit) | 156 | | | 183 | | | 0 | | | 0 | | Amortization of prior service cost (credit) | 579 | | | 156 | | | (133) | | | — | |
Recognized actuarial loss | 5,281 | | | 4,264 | | | (8) | | | 0 | | |
Recognized actuarial loss (gain) | | Recognized actuarial loss (gain) | 3,822 | | | 5,281 | | | (78) | | | (8) | |
Net periodic benefit expense | Net periodic benefit expense | 5,350 | | | 6,079 | | | 840 | | | 1,240 | | Net periodic benefit expense | $ | 3,715 | | | 5,350 | | | 655 | | | 840 | |
Other - curtailment | 0 | | | 586 | | | 0 | | | (1,825) | | |
Other - special termination benefits | 0 | | | 8,435 | | | 0 | | | 0 | | |
Total net periodic benefit expense | $ | 5,350 | | | 15,100 | | | 840 | | | (585) | | |
| | | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Service cost | Service cost | $ | 3,536 | | | 4,332 | | | 653 | | | 893 | | Service cost | $ | 4,258 | | | 3,536 | | | 584 | | | 653 | |
Interest cost | Interest cost | 8,586 | | | 11,554 | | | 1,042 | | | 1,588 | | Interest cost | 10,382 | | | 8,586 | | | 1,148 | | | 1,042 | |
Expected return on plan assets | Expected return on plan assets | (12,288) | | | (12,641) | | | 0 | | | 0 | | Expected return on plan assets | (16,092) | | | (12,288) | | | — | | | — | |
Amortization of prior service cost (credit) | Amortization of prior service cost (credit) | 312 | | | 366 | | | 0 | | | 0 | | Amortization of prior service cost (credit) | 1,179 | | | 312 | | | (266) | | | — | |
Recognized actuarial loss | 10,560 | | | 8,533 | | | (15) | | | 0 | | |
Recognized actuarial loss (gain) | | Recognized actuarial loss (gain) | 7,644 | | | 10,560 | | | (155) | | | (15) | |
Net periodic benefit expense | Net periodic benefit expense | $ | 10,706 | | | 12,144 | | | 1,680 | | | 2,481 | | Net periodic benefit expense | $ | 7,371 | | | 10,706 | | | 1,311 | | | 1,680 | |
Other - curtailment | 0 | | | 586 | | | 0 | | | (1,825) | | |
Other - special termination benefits | 0 | | | 8,435 | | | 0 | | | 0 | | |
Total net periodic benefit expense | $ | 10,706 | | | 21,165 | | | 1,680 | | | 656 | | |
|
The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are includedrecorded in Other income (expense) in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.
During the six-month period ended June 30, 2021,2022, the Company made contributions of $19.5$18.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 20212022 for the Company’s defined benefit pension and postretirement plans is anticipated to be $22.4$24.4 million.
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The 2017 Annual Incentive Plan (2017 Annual Plan)(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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
other employees. Cash awards under the 2017 Annual PlanAIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.
The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5 million5000000 shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I – Incentive Plans(Contd.)
and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.
During the first six months of 2021,2022, the Committee granted the following awards from the 2020 Long-Term Plan:
2020 Long-Term Incentive Plan
| Type of Award | Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology | Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology |
Performance Based RSUs 1 | Performance Based RSUs 1 | 1,156,800 | | | February 2, 2021 | | $ | 16.03 | | | Monte Carlo at Grant Date | Performance Based RSUs 1 | 580,600 | | | February 1, 2022 | | $ | 47.37 | | | Monte Carlo |
| Time Based RSUs 2 | Time Based RSUs 2 | 385,600 | | | February 2, 2021 | | $ | 12.30 | | | Average Stock Price at Grant Date | Time Based RSUs 2 | 273,400 | | | February 1, 2022 | | $ | 32.12 | | | Average Stock Price |
| Cash Settled RSUs 3 | Cash Settled RSUs 3 | 1,022,700 | | | February 2, 2021 | | $ | 12.30 | | | Average Stock Price at Grant Date | 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.
At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with theThe 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan.Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, will bewere made under the 2021 NED Plan.
During the first six months of 2021,2022, the Committee granted the following awards to Non-Employee Directors:
20182021 Stock Plan for Non-Employee Directors
| Type of Award | Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology | Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology |
Time Based RSUs 1 | Time Based RSUs 1 | 182,652 | | | February 3, 2021 | | $ | 13.14 | | | Closing Stock Price at Grant Date | 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 2022.
2021 Stock Plan for Non-Employee Directors
| | | | | | | | | | | | | | | | | | | | | | | |
Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology |
Time Based RSUs 1 | 5,655 | | | June 10, 2021 | | $ | 23.58 | | | Closing Stock Price at Grant Date |
1 Non-employee directors time-based RSUs are scheduled to vest in February 2022.2023.
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 six-month period ended June 30, 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
2022.Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | (Thousands of dollars) | 2021 | | 2020 | (Thousands of dollars) | 2022 | | 2021 |
Compensation charged against income before tax benefit | Compensation charged against income before tax benefit | $ | 18,045 | | | 10,272 | | Compensation charged against income before tax benefit | $ | 34,016 | | | 18,045 | |
Related income tax (expense) benefit recognized in income | 2,478 | | | 769 | | |
Related income tax benefit recognized in income | | Related income tax benefit recognized in income | 5,822 | | | 2,478 | |
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).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note J – Earnings Per Share
Net (loss) incomeloss attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 20212022 and 2020.2021. The following table reports the weighted-average shares outstanding used for these computations.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Weighted-average shares) | (Weighted-average shares) | 2021 | | 2020 | | 2021 | | 2020 | (Weighted-average shares) | 2022 | | 2021 | | 2022 | | 2021 |
Basic method | Basic method | 154,394,602 | | | 153,580,758 | | | 154,153,158 | | | 153,428,666 | | Basic method | 155,388,555 | | | 154,394,602 | | | 155,121,098 | | | 154,153,158 | |
Dilutive stock options and restricted stock units ¹ | 0 | | | 0 | | | 0 | | | 0 | | |
Dilutive stock options and restricted stock units | | Dilutive stock options and restricted stock units | 2,066,575 | | | — | | | 2,730,624 | | | — | |
Diluted method | Diluted method | 154,394,602 | | | 153,580,758 | | | 154,153,158 | | | 153,428,666 | | Diluted method | 157,455,130 | | | 154,394,602 | | | 157,851,722 | | | 154,153,158 | |
1
Due to a net loss recognized by the Company for the three-month and six-month periods ended June 30, 2021, 0 unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Antidilutive stock options excluded from diluted shares | 1,379,481 | | | 2,187,235 | | | 1,592,812 | | | 2,396,920 | |
Weighted average price of these options | $ | 33.79 | | | $ | 39.24 | | | $ | 35.07 | | | $ | 40.83 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
Antidilutive stock options excluded from diluted shares | — | | | 1,379,481 | | | 234,000 | | | 1,592,812 | |
Weighted average price of these options | $ | — | | | $ | 33.79 | | | $ | 49.65 | | | $ | 35.07 | |
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and six-month periods ended June 30, 20212022 and 2020,2021, the Company’s effective income tax rates were as follows:
| | | 2021 | | 2020 | | 2022 | | 2021 |
Three months ended June 30, | Three months ended June 30, | 29.3% | | 22.7% | Three months ended June 30, | 20.4% | | 29.3% |
Six months ended June 30, | Six months ended June 30, | 25.3% | | 18.4% | Six months ended June 30, | 20.3% | | 25.3% |
The effective tax rate for the three-month period ended June 30, 2022 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the three-month period ended June 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of increasing the effective tax rate on an overall loss.
The effective tax rate for the three-monthsix-month period ended June 30, 20202022 was higher thanbelow the U.S. statutory tax rate of 21% principallyprimarily due to a research and developmentno tax creditapplied to the pre-tax income of the noncontrolling interest in Canada,MP GOM offset by exploration expenses in certain foreign jurisdictions in which has the impact of increasing the effectiveno income tax rate.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K– Income Taxes benefit is currently available(Contd.).
The effective tax rate for the six-month period ended June 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to loss generated in Canada, which has a higher tax rate, as well as no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the six-month period ended June 30, 2020 was below the statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. 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 June 30, 2021,2022, 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; and United Kingdom – 2018.2014. Following the divestment of Malaysiasale in the third quarter of 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.
Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss and amortized to the income statement over time. During the six-month period ended June 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.
Commodity Price Risks
At June 30, 2021, theThe Company had 45,000 barrels per day in WTIhas entered into crude oil swap financial contracts maturing through December 2021 at an average price of $42.77,swaps and 20,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2022 at an average price of $44.88.collar contracts. Under thesethe 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 June 30, 2020, the Company had 45,000 barrels2022, volumes per day in WTIassociated with outstanding crude oil swap financialderivative contracts maturing throughand the end of December 2020 at anweighted average price of $56.42, and 2,000 barrels per day in WTI crude oil swapprices for these contracts maturing from January through December 2021 at an average price of $41.54.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 0no foreign currency exchange short-term derivatives outstanding at June 30, 20212022 and 2020.2021.
At June 30, 20212022 and December 31, 2020,2021, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
| | | June 30, 2021 | | December 31, 2020 | | | | | | | | | | | | | | | | | |
(Thousands of dollars) | (Thousands of dollars) | | Asset (Liability) Derivatives | | Asset (Liability) Derivatives | (Thousands of dollars) | | Asset (Liability) Derivatives Fair Value |
Type of Derivative Contract | Type of Derivative Contract | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | Type of Derivative Contract | | Balance Sheet Location | | June 30, 2022 | | December 31, 2021 |
Commodity | | Accounts receivable | | $ | 0 | | | Accounts receivable | | $ | 13,050 | | |
| | Accounts payable | | (354,366) | | | Accounts payable | | (89,842) | | |
Commodity swaps | | Commodity swaps | | Accounts payable | | $ | (239,382) | | | (239,882) | |
| | Deferred credits and other liabilities | | (71,259) | | | Deferred credits and other liabilities | | (12,833) | | |
Commodity collars | | Commodity collars | | Accounts payable | | (146,780) | | | (19,533) | |
Commodity collars | | Commodity collars | | Accounts receivable | | — | | | 4,280 | |
For the three-month and six-month periods ended June 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
For the three-month and six-month periods ended June 30, 2021 and 2020, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
| | | Gain (Loss) | | Gain (Loss) | | Gain (Loss) | | Gain (Loss) |
(Thousands of dollars) | (Thousands of dollars) | | Statement of Operations Location | | Three Months Ended June 30, | | Six months ended June 30, | (Thousands of dollars) | | Statement of Operations Location | | Three Months Ended June 30, | | Six months ended June 30, |
Type of Derivative Contract | Type of Derivative Contract | | 2021 | | 2020 | | 2021 | | 2020 | Type of Derivative Contract | | 2022 | | 2021 | | 2022 | | 2021 |
Commodity | | (Loss) gain on crude contracts | | $ | (226,245) | | | (75,880) | | | $ | (440,630) | | | 324,792 | | |
Commodity swaps | | Commodity swaps | | Loss on crude contracts | | $ | (46,552) | | | (226,245) | | | $ | (202,911) | | | (440,630) | |
Commodity collars | | Commodity collars | | Loss on crude contracts | | (56,516) | | | — | | | (220,934) | | | — | |
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at June 30, 20212022 and December 31, 2020,2021, are presented in the following table.
| | | June 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
(Thousands of dollars) | (Thousands of dollars) | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | (Thousands of dollars) | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets: | Assets: | | Assets: | | | | | | | | | | | | | | | | |
Commodity derivative contracts | | $ | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 13,050 | | | 0 | | | 13,050 | | |
Commodity collars | | Commodity collars | | $ | — | | | — | | | — | | | — | | | — | | | 4,280 | | | — | | | 4,280 | |
| | | $ | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 13,050 | | | 0 | | | 13,050 | | | $ | — | | | — | | | — | | | — | | | — | | | 4,280 | | | — | | | 4,280 | |
| Liabilities: | Liabilities: | | Liabilities: | |
Commodity swaps | | Commodity swaps | | $ | — | | | 239,382 | | | — | | | 239,382 | | | — | | | 239,882 | | | — | | | 239,882 | |
Commodity collars | | Commodity collars | | — | | | 146,780 | | | — | | | 146,780 | | | — | | | 19,533 | | | — | | | 19,533 | |
Contingent consideration | | Contingent consideration | | — | | | — | | | 244,226 | | | 244,226 | | | — | | | — | | | 196,151 | | | 196,151 | |
Nonqualified employee savings plan | Nonqualified employee savings plan | | $ | 17,188 | | | 0 | | | 0 | | | 17,188 | | | 14,988 | | | 0 | | | 0 | | | 14,988 | | Nonqualified employee savings plan | | 17,167 | | | — | | | — | | | 17,167 | | | 16,962 | | | — | | | — | | | 16,962 | |
Commodity derivative contracts | | 0 | | | 425,625 | | | 0 | | | 425,625 | | | 0 | | | 102,675 | | | 0 | | | 102,675 | | |
Contingent consideration | | 0 | | | 0 | | | 209,682 | | | 209,682 | | | 0 | | | 0 | | | 133,004 | | | 133,004 | | |
| | $ | 17,188 | | | 425,625 | | | 209,682 | | | 652,495 | | | 14,988 | | | 102,675 | | | 133,004 | | | 250,667 | | | $ | 17,167 | | | 386,162 | | | 244,226 | | | 647,555 | | | 16,962 | | | 259,415 | | | 196,151 | | | 472,528 | |
The fair value of commodity (WTI crude oil) derivative contracts in 2021 and 2020 wereswaps 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)Loss on crude contracts 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 six months ended June 30, 2022 and 2021, the pre-tax income effect of changes in the fair value of the contingent consideration was an expense of $129.8 million and $76.7 million respectively and is recorded in Other operating expense in the Consolidated Statements of Operations. In the six months ended June 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.
The contingent consideration, related to 2 acquisitions in 2019 and 2018, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other expense (benefit) in the Consolidated Statements of Operations. Contingent consideration is payable annually in years 2022 to 2026.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were 0no offsetting positions recorded at June 30, 20212022 and December 31, 2020.2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 20202021 and June 30, 20212022 and the changes during the six-month period ended June 30, 2021,2022, are presented net of taxes in the following table.
| (Thousands of dollars) | (Thousands of dollars) | Foreign Currency Translation Gains (Losses) | | Retirement and Postretirement Benefit Plan Adjustments | | Deferred Loss on Interest Rate Derivative Hedges | | Total | (Thousands of dollars) | Foreign Currency Translation Gains (Losses) | | Retirement and Postretirement Benefit Plan Adjustments | | | Total |
Balance at December 31, 2020 | $ | (324,011) | | | (275,632) | | | (1,690) | | | (601,333) | | |
Balance at December 31, 2021 | | Balance at December 31, 2021 | $ | (311,895) | | | (215,816) | | | | (527,711) | |
Components of other comprehensive income (loss): | Components of other comprehensive income (loss): | | Components of other comprehensive income (loss): | | | |
Before reclassifications to income and retained earnings | Before reclassifications to income and retained earnings | 37,842 | | | 0 | | | 0 | | | 37,842 | | Before reclassifications to income and retained earnings | (33,525) | | | — | | | | (33,525) | |
Reclassifications to income | Reclassifications to income | 0 | | | 8,282 | | ¹ | 1,690 | | ² | 9,972 | | Reclassifications to income | — | | | 6,509 | | ¹ | | 6,509 | |
Net other comprehensive income (loss) | Net other comprehensive income (loss) | 37,842 | | | 8,282 | | | 1,690 | | | 47,814 | | Net other comprehensive income (loss) | (33,525) | | | 6,509 | | | | (27,016) | |
Balance at June 30, 2021 | $ | (286,169) | | | (267,350) | | | 0 | | | (553,519) | | |
Balance at June 30, 2022 | | Balance at June 30, 2022 | $ | (345,420) | | | (209,307) | | | | (554,727) | |
1 Reclassifications before taxes of $10,513$8,256 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2021.2022. See Note H for additional information. Related income taxes of $2,231$1,747 are included in Income tax expense (benefit) for the six-month period ended June 30, 2021. 2 Reclassifications before taxes of $2,140 are included in Interest expense, net, for the six-month period ended June 30, 2021. Related income taxes of $450 are included in Income tax expense (benefit) for the six-month period ended June 30, 2021. See Note L for additional information.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. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
ENVIRONMENTAL, HEALTH AND SAFETY MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. 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 federal or state 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.
The Biden administration has indicated that it intends to increase regulatory oversight of the oil and gas industry, with a focus on climate change and greenhouse gas emissions (including methane emissions). The Biden administration has issued a number of executive orders that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. The Biden administration has also issued orders related to oil and gas activities on federal lands,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
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, under the Biden administration it 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note O – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts)commodity price derivatives), interest expense and unallocated overhead, is shown in the tablestable to reconcile the business segments to consolidated totals.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets at June 30, 2021 | | Three Months Ended June 30, 2021 | | Three Months Ended June 30, 2020 |
(Millions of dollars) | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | $ | 6,868.2 | | | 648.9 | | | 194.7 | | | 228.3 | | | (143.1) | |
Canada | | 2,366.7 | | | 120.6 | | | 12.7 | | | 59.2 | | | (19.5) | |
Other | | 270.4 | | | 0 | | | (10.4) | | | 0 | | | (9.0) | |
Total exploration and production | | 9,505.3 | | | 769.5 | | | 197.0 | | | 287.5 | | | (171.6) | |
Corporate | | 1,097.7 | | | (219.9) | | | (223.9) | | | (76.0) | | | (151.6) | |
Continuing operations | | 10,603.0 | | | 549.6 | | | (26.9) | | | 211.5 | | | (323.2) | |
Discontinued operations, net of tax | | 1.2 | | | 0 | | | (0.1) | | | 0 | | | (1.2) | |
Total | | $ | 10,604.2 | | | 549.6 | | | (27.0) | | | 211.5 | | | (324.4) | |
| | | | | | | | | | |
| | | | Six Months Ended June 30, 2021 | | Six Months Ended June 30, 2020 |
(Millions of dollars) | | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | | | 1,139.2 | | | 313.7 | | | 739.8 | | | (839.1) | |
Canada | | | | 224.6 | | | (111.6) | | | 148.9 | | | (26.4) | |
Other | | | | 0 | | | (17.3) | | | 1.8 | | | (61.3) | |
Total exploration and production | | | | 1,363.8 | | | 184.8 | | | 890.5 | | | (926.8) | |
Corporate | | | | (434.2) | | | (478.8) | | | 324.8 | | | 99.8 | |
Continuing operations | | | | 929.6 | | | (294.0) | | | 1,215.3 | | | (827.0) | |
Discontinued operations, net of tax | | | | 0 | | | 0.1 | | | 0 | | | (6.1) | |
Total | | | | 929.6 | | | (293.9) | | | 1,215.3 | | | (833.1) | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets at June 30, 2022 | | Three Months Ended June 30, 2022 | | Three Months Ended June 30, 2021 |
(Millions of dollars) | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | $ | 7,034.9 | | | 978.0 | | | 491.5 | | | 648.9 | | | 194.7 | |
Canada | | 2,250.1 | | | 206.6 | | | 47.2 | | | 120.6 | | | 12.7 | |
Other | | 244.9 | | | 13.7 | | | (3.5) | | | — | | | (10.4) | |
Total exploration and production | | 9,529.9 | | | 1,198.3 | | | 535.2 | | | 769.5 | | | 197.0 | |
Corporate | | 1,041.3 | | | (97.2) | | | (124.8) | | | (219.9) | | | (223.9) | |
Continuing operations | | 10,571.2 | | | 1,101.1 | | | 410.4 | | | 549.6 | | | (26.9) | |
Discontinued operations, net of tax | | 1.0 | | | — | | | (0.9) | | | — | | | (0.1) | |
Total | | $ | 10,572.2 | | | 1,101.1 | | | 409.5 | | | 549.6 | | | (27.0) | |
| | | | | | | | | | |
| | | | Six Months Ended June 30, 2022 | | Six Months Ended June 30, 2021 |
(Millions of dollars) | | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | | | 1,685.4 | | | 744.4 | | | 1,139.2 | | | 313.7 | |
Canada | | | | 372.7 | | | 69.9 | | | 224.6 | | | (111.6) | |
Other | | | | 13.7 | | | (47.7) | | | — | | | (17.3) | |
Total exploration and production | | | | 2,071.8 | | | 766.6 | | | 1,363.8 | | | 184.8 | |
Corporate | | | | (417.8) | | | (421.1) | | | (434.2) | | | (478.8) | |
Continuing operations | | | | 1,654.0 | | | 345.5 | | | 929.6 | | | (294.0) | |
Discontinued operations, net of tax | | | | — | | | (1.5) | | | — | | | 0.1 | |
Total | | | | 1,654.0 | | | 344.0 | | | 929.6 | | | (293.9) | |
1 Additional details about results of oil and natural gas operations are presented in the tabletables on pages 26page 25 and 27.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note P – Leases
Nature of Leases
The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 19 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.
Related Expenses
Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Thousands of dollars) | | Financial Statement Category | | 2021 | | 2020 | | 2021 | | 2020 |
Operating lease 1,2 | | Lease operating expenses | | $ | 48,049 | | | $ | 53,588 | | | $ | 94,133 | | | 125,189 | |
Operating lease 2 | | Transportation, gathering and processing | | 9,982 | | | 9,137 | | | 19,758 | | | 19,063 | |
Operating lease 2 | | Selling and general expense | | 2,453 | | | 3,281 | | | 5,273 | | | 6,750 | |
Operating lease 2 | | Other operating expense | | 2,427 | | | 4,201 | | | 4,842 | | | 4,615 | |
Operating lease 2 | | Property, plant and equipment | | 26,738 | | | 13,104 | | | 31,634 | | | 37,660 | |
| | | | | | | | | | |
Operating lease | | Impairment of assets | | 0 | | | 6,555 | | | 0 | | | 6,555 | |
Finance lease | | | | | | | | | | |
| | | | | | | | | | |
Interest on lease liabilities | | Interest expense, net | | 86 | | | 92 | | | 172 | | | 188 | |
Sublease income | | Other income | | (662) | | | (336) | | | (958) | | | (642) | |
Net lease expense | | | | $ | 89,073 | | | $ | 89,636 | | | $ | 154,854 | | | 199,392 | |
1 Variable lease expenses. The three and six months ended June 30, 2021 included variable lease expenses of $8.2 million and $13.5 million; and for the three and six months ended June 30, 2020 included variable lease expenses of $6.0 million and $12.3 million, respectively, primarily related to additional volumes processed at a gas processing plant.
2 Short-term leases due within 12 months.The three and six months ended June 30, 2021 included $11.1 million and $23.5 million for Lease operating expense, $7.6 million and $14.9 million for Transportation, gathering and processing, $0.5 million and $1.3 million for Selling and general expense and $10.0 million and $14.9 million for Property, plant and equipment, net relating to short term leases due within 12 months. The three and six months ended June 30, 2020 included $21.4 million and $54.3 million for Lease operating expense, $6.6 million and $8.0 million for Transportation, gathering and processing, $1.0 million and $2.2 million for Selling and general expense, $7.5 million and $22.9 million for Property, plant and equipment, net, and $2.4 million for other operating expense relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.
Maturity of Lease Liabilities
| | | | | | | | | | | | | | | | | |
(Thousands of dollars) | Operating Leases | | Finance Leases | | Total |
2021 | $ | 109,284 | | | 534 | | | 109,818 | |
2022 | 185,790 | | | 1,068 | | | 186,858 | |
2023 | 138,692 | | | 1,069 | | | 139,761 | |
2024 | 133,502 | | | 1,069 | | | 134,571 | |
2025 | 83,210 | | | 1,069 | | | 84,279 | |
Remaining | 726,103 | | | 3,472 | | | 729,575 | |
Total future minimum lease payments | 1,376,581 | | | 8,281 | | | 1,384,862 | |
Less imputed interest | (382,394) | | | (1,403) | | | (383,797) | |
Present value of lease liabilities 1 | $ | 994,187 | | | 6,878 | | | 1,001,065 | |
1Includes both the current and long-term portion of the lease liabilities.26.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note P – Leases (Contd.)
Lease Term and Discount Rate
| | | | | |
| June 30, 2021 |
Weighted average remaining lease term: | |
Operating leases | 11 years |
Finance leases | 8 years |
Weighted average discount rate: | |
Operating leases | 5.4 | % |
Finance leases | 4.7 | % |
Other Information
| | | | | | | | | | | |
| Six Months Ended June 30, |
(Thousands of dollars) | 2021 | | 2020 |
Cash paid for amounts included in the measurement of lease liabilities: | | | |
Operating cash flows from operating leases | $ | 87,768 | | | $ | 90,831 | |
Operating cash flows from finance leases | 172 | | | 188 | |
Financing cash flows from finance leases | 371 | | | 336 | |
Right-of-use assets obtained in exchange for lease liabilities: | | | |
Operating leases ¹ | $ | 94,788 | | | 277,662 | |
1The six months ended June 30, 2021 includes $90.3 million related to an offshore drilling rig with a lease term of 16 months. The six months ended June 30, 2020 includes $268.8 million related to a 5-year lease for the Cascade/Chinook FPSO in the U.S. Gulf of Mexico.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In 2021, the global disseminationsecond quarter of several vaccinations in response2022, crude oil and natural gas benchmark prices increased compared to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to increased economic activity and subsequently increased demand for oil and gas. However emerging COVID-19 variants, such as the Delta variant, continue to create uncertaintysame period of 2021. Prices were higher in the outlook for futuresecond quarter 2022 principally due to continued market concerns over supply shortfalls stemming from lack of investment in the exploration and production sector, demand forrecovery from COVID-19 as well as geopolitical uncertainty and market disruption following the Russian invasion of Ukraine.
Similar to the overall inflation in the wider economy, the oil and gas industry, and hence volatilitythe Company, is observing higher costs for goods and services used in currentexploration and future prices for Murphy’s product.
In the current quarter and first half of 2021, overall energy demand has recovered significantly compared to 2020. The OPEC+ group of oil producing countries (OPEC+)production operations. Murphy continues to constrainmanage input costs through its dedicated procurement department focused on managing supply however these are being gradually scaled back as 2021 progresses. OPEC+ last year cut production by 10 million barrels per day (bpd) following the COVID-19 demand reduction. It has gradually reinstated supply so that the curtailments are approximately 5.8 million bpd at the end of June 2021. From July to December 2021 OPEC+ has reported it will increase supply by a 0.4 million bpd a month, with aims to fully phase out cuts by September 2022.
Overall the combination of OPEC+ supply constraintschain and the increase in demand driven by the global COVID-19 vaccine roll out has provided upwards pressure to the oil price which directly impacts the Company’s product revenue from sales compared to one year ago.other costs.
For the three months ended June 30, 2021,2022, West Texas Intermediate (WTI) crude oil prices averaged approximately $66$108.41 per barrel (compared to $58$94.29 in the first quarter of 20212022 and $28$66.07 in the second quarter of 2020)2021). The closingaverage price for WTI at the endin June of the second quarter of 20212022 was approximately $71$114.34 per barrel, reflecting a 52%60% increase from June of 2021 and a 6% increase from the average price at the endfrom March of 2020 and a 14% increase from the first quarter 2021 closing price.2022. The average price in July 20212022 was $72.43$99.38 per barrel. As of close on August 3, 2021,2, 2022, the NYMEX WTI forward curve priceprices for the remainder of 20212022 and 20222023 were $69.71$92.82 and $65.34$86.14 per barrel, respectively.
For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the GOM Kodiak field. The Company reported net income from continuing operations of $410.4 million for the three months ended June 30, 2022; this amount includes income attributable to noncontrolling interest of $58.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $69.6 million and after-tax losses on contingent consideration of $25.1 million.
In the second quarter of 2022, the Company achieved first production from the first four wells 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 and storage facility.
In June 2022, the Company acquired an additional 11.0% working interest (there is no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million.
For the three months ended June 30, 2021, the Company produced 182 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Companyoperations and invested $207.1 million in capital expenditures (on a value of work done basis) in the three months ended June 30, 2021.. The Company reported net loss from continuing operations of $26.9 million for the three months ended June 30,second quarter of 2021. This amount includesincluded income attributable to noncontrolling interest of $36.0 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $103.3 million and $48.8 million, respectively.
For the six months ended June 30, 2021, the Company produced 174 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $458.2 million in capital expenditures (on a value of work done basis) in the six months ended June 30, 2021, which included $17.3 million to fund the development of the King’s Quay Floating Production System (FPS). The FPS capital expenditures were reimbursed by Arclight inIn the first quarter of 2021, (see below). The Company reported net loss from continuing operations of $294.0 million for the six months ended June 30, 2021. This amount includes income attributable to noncontrolling interest of $56.7 million, after-tax impairment charges of $128.0 million, and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $224.6 million and $60.6 million, respectively.
For the three months ended June 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $179.6 million in capital expenditures (on a value of work done basis), in the second quarter of 2020, which included $32.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $323.1 million for the second quarter of 2020. This amount included loss attributable to noncontrolling interest of $7.2 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions of $145.8 million.
For the six months ended June 30, 2020, the Company produced 189 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $557.6 million in capital expenditures (on a value of work done basis) for the six months ended June 30, 2020, which included $61.4 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $827.0 million for the six months ended June 30, 2020. This amount included loss attributable to noncontrolling interest of $99.8 million, after-tax impairment charges of $708.3 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions of $137.3 million.
During the six months ended June 30, 2021, crude oil and condensate volumes from continuing operations were lower than the prior year period. The decrease in production volumes is due to reduced capital expenditures throughout 2020 and the first
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Summary (contd.)
quarter of 2021 to support generating positive free cash flow. Revenue from sales to customers was 52% higher during the first half of 2021 compared to the first half of 2020, primarily driven by the change in price.
In the first half of 2021, the Company’s subsidiary, "MurphyMurphy Exploration & Production Company USA"- USA, closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the sale of Murphy’s entire 50% interest in the King’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of project costs from inception to closing with proceeds of $267.7 million.
Also,For the six months ended June 30, 2022, the Company produced 162 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $621.9 million in capital expenditures (on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat exploration well in Brazil deferred from 2021). The Company reported net income from continuing operations of $345.5 million for the six months ended June 30, 2022. This amount includes income attributable to noncontrolling interest of $106.8 million and after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration of $79.3 million and $102.3 million, respectively.
For the six months ended June 30, 2021, the Company produced 174 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $458.2 million in capital expenditures (on a value of work done basis), which included $17.3 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 $294.0 million for the six months ended June 30, 2021. This amount included income attributable to noncontrolling interest of $56.7 million, after-tax impairment charges of $128.0 million and after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration of $224.6 million and $60.6 million, respectively.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Summary (contd.)
During the six months ended June 30, 2022, crude oil and condensate volumes from continuing operations were lower than the prior year period. The decrease in production volumes is due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders. Revenue from production was 47% higher during the first half of 2022 compared to the first half of 2021, primarily driven by the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturingincrease in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which includes redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and incurred closing costs of $8.0 million. The proceeds from issue are reported net of costs to issue on the balance sheet.price.
Results of Operations
Murphy’s income (loss) by type of business is presented below.
| | | Income (Loss) | | Income (Loss) |
| | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Millions of dollars) | (Millions of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Millions of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Exploration and production | Exploration and production | $ | 197.0 | | | (171.6) | | | 184.8 | | | (926.8) | | Exploration and production | $ | 535.2 | | | 197.0 | | | $ | 766.6 | | | 184.8 | |
Corporate and other | Corporate and other | (223.9) | | | (151.6) | | | (478.8) | | | 99.8 | | Corporate and other | (124.8) | | | (223.9) | | | (421.1) | | | (478.8) | |
(Loss) income from continuing operations | (26.9) | | | (323.2) | | | (294.0) | | | (827.0) | | |
Income (loss) from continuing operations | | Income (loss) from continuing operations | 410.4 | | | (26.9) | | | 345.5 | | | (294.0) | |
Discontinued operations ¹ | Discontinued operations ¹ | (0.1) | | | (1.2) | | | 0.1 | | | (6.1) | | Discontinued operations ¹ | (0.9) | | | (0.1) | | | (1.5) | | | 0.1 | |
Net (loss) income including noncontrolling interest | $ | (27.0) | | | (324.4) | | | (293.9) | | | (833.1) | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | 409.5 | | | (27.0) | | | $ | 344.0 | | | (293.9) | |
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) | | Income (Loss) |
| | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Millions of dollars) | (Millions of dollars) | 2021 | | 2020 | | 2021 | | 2020 | (Millions of dollars) | 2022 | | 2021 | | 2022 | | 2021 |
Exploration and production | Exploration and production | | | | | | | | Exploration and production | | | | | | | |
United States | United States | $ | 194.7 | | | (143.1) | | | 313.7 | | | (839.1) | | United States | $ | 491.5 | | | 194.7 | | | $ | 744.4 | | | 313.7 | |
Canada | Canada | 12.7 | | | (19.5) | | | (111.6) | | | (26.4) | | Canada | 47.2 | | | 12.7 | | | 69.9 | | | (111.6) | |
Other | Other | (10.4) | | | (9.0) | | | (17.3) | | | (61.3) | | Other | (3.5) | | | (10.4) | | | (47.7) | | | (17.3) | |
Total | Total | $ | 197.0 | | | (171.6) | | | 184.8 | | | (926.8) | | Total | $ | 535.2 | | | 197.0 | | | $ | 766.6 | | | 184.8 | |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(Millions of dollars, except per barrel of oil equivalents sold) | (Millions of dollars, except per barrel of oil equivalents sold) | 2021 | | 2020 | | 2021 | | 2020 | (Millions of dollars, except per barrel of oil equivalents sold) | 2022 | | 2021 | | 2022 | | 2021 |
Net loss attributable to Murphy (GAAP) | $ | (63.1) | | | (317.1) | | | (350.5) | | | (733.2) | | |
Income tax benefit | (11.2) | | | (94.8) | | | (99.3) | | | (186.3) | | |
Net income (loss) attributable to Murphy (GAAP) | | Net income (loss) attributable to Murphy (GAAP) | $ | 350.6 | | | (63.1) | | | $ | 237.2 | | | (350.5) | |
Income tax expense (benefit) | | Income tax expense (benefit) | 105.1 | | | (11.2) | | | 88.1 | | | (99.3) | |
Interest expense, net | Interest expense, net | 43.4 | | | 38.6 | | | 131.5 | | | 79.7 | | Interest expense, net | 41.4 | | | 43.4 | | | 78.7 | | | 131.5 | |
Depreciation, depletion and amortization expense ¹ | Depreciation, depletion and amortization expense ¹ | 217.3 | | | 219.1 | | | 405.6 | | | 505.3 | | Depreciation, depletion and amortization expense ¹ | 188.2 | | | 217.3 | | | 344.8 | | | 405.6 | |
EBITDA attributable to Murphy (Non-GAAP) | EBITDA attributable to Murphy (Non-GAAP) | 186.4 | | | (154.2) | | | 87.3 | | | (334.5) | | EBITDA attributable to Murphy (Non-GAAP) | 685.3 | | | 186.4 | | | 748.8 | | | 87.3 | |
Mark-to-market loss (gain) on crude oil derivative contracts | 130.9 | | | 184.5 | | | 284.4 | | | (173.8) | | |
Mark-to-market (gain) loss on derivative instruments | | Mark-to-market (gain) loss on derivative instruments | (88.1) | | | 130.9 | | | 100.4 | | | 284.4 | |
Mark-to-market loss on contingent consideration | | Mark-to-market loss on contingent consideration | 31.7 | | | 61.8 | | | 129.8 | | | 76.7 | |
Accretion of asset retirement obligations ¹ | | Accretion of asset retirement obligations ¹ | 10.2 | | | 9.5 | | | 20.7 | | | 20.0 | |
Discontinued operations loss (income) | | Discontinued operations loss (income) | 0.9 | | | 0.1 | | | 1.5 | | | (0.1) | |
Foreign exchange (gain) loss | | Foreign exchange (gain) loss | (8.0) | | | — | | | (8.0) | | | 1.3 | |
Impairment of assets ¹ | Impairment of assets ¹ | — | | | 19.6 | | | 171.3 | | | 886.0 | | Impairment of assets ¹ | — | | | — | | | — | | | 171.3 | |
Mark-to-market loss (gain) on contingent consideration | 61.8 | | | 15.7 | | | 76.7 | | | (43.5) | | |
Accretion of asset retirement obligations ¹ | 9.5 | | | 10.5 | | | 20.0 | | | 20.4 | | |
Unutilized rig charges | Unutilized rig charges | 2.5 | | | 4.5 | | | 5.3 | | | 8.0 | | Unutilized rig charges | — | | | 2.5 | | | — | | | 5.3 | |
Foreign exchange losses (gains) | — | | | 1.4 | | | 1.3 | | | (3.3) | | |
Discontinued operations (income) loss | 0.1 | | | 1.2 | | | (0.1) | | | 6.1 | | |
Restructuring expenses | — | | | 41.4 | | | — | | | 41.4 | | |
Inventory loss | — | | | — | | | — | | | 4.8 | | |
| | Adjusted EBITDA attributable to Murphy (Non-GAAP) | Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 391.2 | | | 124.6 | | | 646.2 | | | 411.6 | | Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 632.0 | | | 391.2 | | | $ | 993.2 | | | 646.2 | |
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 15,648 | | | 15,242 | | | 29,318 | | | 32,312 | | Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 14,884 | | | 15,648 | | | 27,449 | | | 29,318 | |
| Adjusted EBITDA per barrel of oil equivalents sold | Adjusted EBITDA per barrel of oil equivalents sold | $ | 25.00 | | | 8.17 | | | 22.04 | | | 12.74 | | Adjusted EBITDA per barrel of oil equivalents sold | $ | 42.46 | | | 25.00 | | | $ | 36.18 | | | 22.04 | |
1 Depreciation, depletion, and amortization expense, impairment of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2022 AND 2021
| | | | | | | | | | | | | | | | | | | | | | | |
(Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Three Months Ended June 30, 2022 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 977.8 | | | 156.8 | | | 13.7 | | | 1,148.3 | |
Sales of purchased natural gas | 0.2 | | | 49.8 | | | — | | | 50.0 | |
Lease operating expenses | 109.5 | | | 36.9 | | | 0.9 | | | 147.3 | |
Severance and ad valorem taxes | 17.3 | | | 0.3 | | | — | | | 17.6 | |
Transportation, gathering and processing | 32.3 | | | 17.6 | | | — | | | 49.9 | |
Costs of purchased natural gas | 0.2 | | | 47.7 | | | — | | | 47.9 | |
Depreciation, depletion and amortization | 153.7 | | | 35.6 | | | 3.4 | | | 192.7 | |
| | | | | | | |
Accretion of asset retirement obligations | 9.1 | | | 2.4 | | | 0.1 | | | 11.6 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | (0.7) | | | — | | | 2.0 | | | 1.3 | |
Geological and geophysical | — | | | 0.1 | | | 0.8 | | | 0.9 | |
Other exploration | 2.9 | | | 0.3 | | | 6.0 | | | 9.2 | |
| 2.2 | | | 0.4 | | | 8.8 | | | 11.4 | |
Undeveloped lease amortization | 2.3 | | | — | | | 1.4 | | | 3.7 | |
Total exploration expenses | 4.5 | | | 0.4 | | | 10.2 | | | 15.1 | |
Selling and general expenses | 3.2 | | | 3.8 | | | 2.1 | | | 9.1 | |
Other | 35.3 | | | (2.3) | | | — | | | 33.0 | |
Results of operations before taxes | 612.9 | | | 64.2 | | | (3.0) | | | 674.1 | |
Income tax provisions | 121.4 | | | 17.0 | | | 0.5 | | | 138.9 | |
Results of operations (excluding Corporate segment) | $ | 491.5 | | | 47.2 | | | (3.5) | | | 535.2 | |
| | | | | | | |
Three Months Ended June 30, 2021 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 648.9 | | | 120.6 | | | — | | | 769.5 | |
| | | | | | | |
Lease operating expenses | 90.5 | | | 35.8 | | | — | | | 126.3 | |
Severance and ad valorem taxes | 10.9 | | | 0.5 | | | — | | | 11.4 | |
Transportation, gathering and processing | 33.6 | | | 16.1 | | | — | | | 49.7 | |
| | | | | | | |
Depreciation, depletion and amortization | 180.0 | | | 43.5 | | | 0.5 | | | 224.0 | |
Accretion of asset retirement obligations | 9.2 | | | 3.0 | | | — | | | 12.2 | |
| | | | | | | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | (0.1) | | | — | | | — | | | (0.1) | |
Geological and geophysical | 2.1 | | | — | | | 0.8 | | | 2.9 | |
Other exploration | 2.3 | | | 0.1 | | | 4.1 | | | 6.5 | |
| 4.3 | | | 0.1 | | | 4.9 | | | 9.3 | |
Undeveloped lease amortization | 2.5 | | | — | | | 1.8 | | | 4.3 | |
Total exploration expenses | 6.8 | | | 0.1 | | | 6.7 | | | 13.6 | |
Selling and general expenses | 5.3 | | | 3.9 | | | 2.1 | | | 11.3 | |
Other | 72.9 | | | 0.9 | | | 0.3 | | | 74.1 | |
Results of operations before taxes | 239.7 | | | 16.8 | | | (9.6) | | | 246.9 | |
Income tax provisions | 45.0 | | | 4.1 | | | 0.8 | | | 49.9 | |
Results of operations (excluding Corporate segment) | $ | 194.7 | | | 12.7 | | | (10.4) | | | 197.0 | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREESIX MONTHS ENDED JUNE 30, 20212022 AND 20202021
| (Millions of dollars) | (Millions of dollars) | United States 1 | | Canada | | Other | | Total | (Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Three Months Ended June 30, 2021 | | | | | | | | |
Six Months Ended June 30, 2022 | | Six Months Ended June 30, 2022 | | | | | | | |
Oil and gas sales and other operating revenues | Oil and gas sales and other operating revenues | $ | 648.9 | | | 120.6 | | | — | | | 769.5 | | Oil and gas sales and other operating revenues | $ | 1,685.2 | | | 286.1 | | | 13.7 | | | 1,985.0 | |
Sales of purchased natural gas | | Sales of purchased natural gas | 0.2 | | | 86.6 | | | — | | | 86.8 | |
Lease operating expenses | Lease operating expenses | 90.5 | | | 35.8 | | | — | | | 126.3 | | Lease operating expenses | 209.4 | | | 73.8 | | | 0.9 | | | 284.1 | |
Severance and ad valorem taxes | Severance and ad valorem taxes | 10.9 | | | 0.5 | | | — | | | 11.4 | | Severance and ad valorem taxes | 31.5 | | | 0.7 | | | — | | | 32.2 | |
Transportation, gathering and processing | Transportation, gathering and processing | 33.6 | | | 16.1 | | | — | | | 49.7 | | Transportation, gathering and processing | 61.5 | | | 35.3 | | | — | | | 96.8 | |
Costs of purchased natural gas | | Costs of purchased natural gas | 0.2 | | | 81.4 | | | — | | | 81.6 | |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | 180.0 | | | 43.5 | | | 0.5 | | | 224.0 | | Depreciation, depletion and amortization | 280.2 | | | 69.8 | | | 3.5 | | | 353.5 | |
Accretion of asset retirement obligations | | Accretion of asset retirement obligations | 18.5 | | | 4.9 | | | 0.1 | | | 23.5 | |
| Accretion of asset retirement obligations | 9.2 | | | 3.0 | | | — | | | 12.2 | | |
Exploration expenses | Exploration expenses | | Exploration expenses | |
Dry holes and previously suspended exploration costs | Dry holes and previously suspended exploration costs | (0.1) | | | — | | | — | | | (0.1) | | Dry holes and previously suspended exploration costs | (0.7) | | | — | | | 34.8 | | | 34.1 | |
Geological and geophysical | Geological and geophysical | 2.1 | | | — | | | 0.8 | | | 2.9 | | Geological and geophysical | 2.6 | | | 0.1 | | | 1.0 | | | 3.7 | |
Other exploration | Other exploration | 2.3 | | | 0.1 | | | 4.1 | | | 6.5 | | Other exploration | 4.4 | | | 0.4 | | | 12.1 | | | 16.9 | |
| | 4.3 | | | 0.1 | | | 4.9 | | | 9.3 | | | 6.3 | | | 0.5 | | | 47.9 | | | 54.7 | |
Undeveloped lease amortization | Undeveloped lease amortization | 2.5 | | | — | | | 1.8 | | | 4.3 | | Undeveloped lease amortization | 4.7 | | | 0.1 | | | 3.2 | | | 8.0 | |
Total exploration expenses | Total exploration expenses | 6.8 | | | 0.1 | | | 6.7 | | | 13.6 | | Total exploration expenses | 11.0 | | | 0.6 | | | 51.1 | | | 62.7 | |
Selling and general expenses | Selling and general expenses | 5.3 | | | 3.9 | | | 2.1 | | | 11.3 | | Selling and general expenses | 11.5 | | | 8.9 | | | 4.5 | | | 24.9 | |
Other | Other | 72.9 | | | 0.9 | | | 0.3 | | | 74.1 | | Other | 138.1 | | | 2.8 | | | 0.4 | | | 141.3 | |
Results of operations before taxes | Results of operations before taxes | 239.7 | | | 16.8 | | | (9.6) | | | 246.9 | | Results of operations before taxes | 923.5 | | | 94.5 | | | (46.8) | | | 971.2 | |
Income tax provisions (benefits) | Income tax provisions (benefits) | 45.0 | | | 4.1 | | | 0.8 | | | 49.9 | | Income tax provisions (benefits) | 179.1 | | | 24.6 | | | 0.9 | | | 204.6 | |
Results of operations (excluding Corporate segment) | Results of operations (excluding Corporate segment) | $ | 194.7 | | | 12.7 | | | (10.4) | | | 197.0 | | Results of operations (excluding Corporate segment) | $ | 744.4 | | | 69.9 | | | (47.7) | | | 766.6 | |
| Three Months Ended June 30, 2020 | | |
Six months ended June 30, 2021 | | Six months ended June 30, 2021 | |
Oil and gas sales and other operating revenues | Oil and gas sales and other operating revenues | $ | 228.3 | | | 59.2 | | | — | | | 287.5 | | Oil and gas sales and other operating revenues | $ | 1,139.2 | | | 224.6 | | | — | | | 1,363.8 | |
| Lease operating expenses | Lease operating expenses | 116.8 | | | 27.4 | | | 0.5 | | | 144.7 | | Lease operating expenses | 206.6 | | | 66.6 | | | 0.3 | | | 273.5 | |
Severance and ad valorem taxes | Severance and ad valorem taxes | 6.1 | | | 0.4 | | | — | | | 6.5 | | Severance and ad valorem taxes | 19.8 | | | 0.8 | | | — | | | 20.6 | |
Transportation, gathering and processing | Transportation, gathering and processing | 31.5 | | | 9.6 | | | — | | | 41.1 | | Transportation, gathering and processing | 62.1 | | | 30.5 | | | — | | | 92.6 | |
| Depreciation, depletion and amortization | Depreciation, depletion and amortization | 175.8 | | | 49.7 | | | 0.5 | | | 226.0 | | Depreciation, depletion and amortization | 329.6 | | | 88.3 | | | 1.0 | | | 418.9 | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 9.1 | | | 1.3 | | | — | | | 10.4 | | Accretion of asset retirement obligations | 18.2 | | | 4.5 | | | — | | | 22.7 | |
Impairment of assets | Impairment of assets | 19.6 | | | — | | | — | | | 19.6 | | Impairment of assets | — | | | 171.3 | | | — | | | 171.3 | |
Exploration expenses | Exploration expenses | | Exploration expenses | |
Dry holes and previously suspended exploration costs | Dry holes and previously suspended exploration costs | 7.6 | | | — | | | — | | | 7.6 | | Dry holes and previously suspended exploration costs | 0.6 | | | — | | | — | | | 0.6 | |
Geological and geophysical | Geological and geophysical | 8.0 | | | 0.1 | | | 0.5 | | | 8.6 | | Geological and geophysical | 2.7 | | | — | | | 1.0 | | | 3.7 | |
Other exploration | Other exploration | 2.9 | | | 0.1 | | | 3.0 | | | 6.0 | | Other exploration | 2.9 | | | 0.1 | | | 9.1 | | | 12.1 | |
| | 18.5 | | | 0.2 | | | 3.5 | | | 22.2 | | | 6.2 | | | 0.1 | | | 10.1 | | | 16.4 | |
Undeveloped lease amortization | Undeveloped lease amortization | 4.8 | | | — | | | 2.4 | | | 7.2 | | Undeveloped lease amortization | 4.8 | | | 0.1 | | | 4.0 | | | 8.9 | |
Total exploration expenses | Total exploration expenses | 23.3 | | | 0.2 | | | 5.9 | | | 29.4 | | Total exploration expenses | 11.0 | | | 0.2 | | | 14.1 | | | 25.3 | |
Selling and general expenses | Selling and general expenses | 7.6 | | | 5.4 | | | 2.3 | | | 15.3 | | Selling and general expenses | 10.8 | | | 8.0 | | | 3.5 | | | 22.3 | |
Other | Other | 24.2 | | | (1.2) | | | 0.1 | | | 23.1 | | Other | 94.4 | | | 4.0 | | | (3.2) | | | 95.2 | |
Results of operations before taxes | Results of operations before taxes | (185.7) | | | (33.6) | | | (9.3) | | | (228.6) | | Results of operations before taxes | 386.7 | | | (149.6) | | | (15.7) | | | 221.4 | |
Income tax provisions (benefits) | Income tax provisions (benefits) | (42.6) | | | (14.1) | | | (0.3) | | | (57.0) | | Income tax provisions (benefits) | 73.0 | | | (38.0) | | | 1.6 | | | 36.6 | |
Results of operations (excluding Corporate segment) | Results of operations (excluding Corporate segment) | $ | (143.1) | | | (19.5) | | | (9.0) | | | (171.6) | | Results of operations (excluding Corporate segment) | $ | 313.7 | | | (111.6) | | | (17.3) | | | 184.8 | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2021 AND 2020
| | | | | | | | | | | | | | | | | | | | | | | |
(Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Six Months Ended June 30, 2021 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 1,139.2 | | | 224.6 | | | — | | | 1,363.8 | |
Lease operating expenses | 206.6 | | | 66.6 | | | 0.3 | | | 273.5 | |
Severance and ad valorem taxes | 19.8 | | | 0.8 | | | — | | | 20.6 | |
Transportation, gathering and processing | 62.1 | | | 30.5 | | | — | | | 92.6 | |
Depreciation, depletion and amortization | 329.6 | | | 88.3 | | | 1.0 | | | 418.9 | |
Accretion of asset retirement obligations | 18.2 | | | 4.5 | | | — | | | 22.7 | |
Impairment of assets | — | | | 171.3 | | | — | | | 171.3 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | 0.6 | | | — | | | — | | | 0.6 | |
Geological and geophysical | 2.7 | | | — | | | 1.0 | | | 3.7 | |
Other exploration | 2.9 | | | 0.1 | | | 9.1 | | | 12.1 | |
| 6.2 | | | 0.1 | | | 10.1 | | | 16.4 | |
Undeveloped lease amortization | 4.8 | | | 0.1 | | | 4.0 | | | 8.9 | |
Total exploration expenses | 11.0 | | | 0.2 | | | 14.1 | | | 25.3 | |
Selling and general expenses | 10.8 | | | 8.0 | | | 3.5 | | | 22.3 | |
Other | 94.4 | | | 4.0 | | | (3.2) | | | 95.2 | |
Results of operations before taxes | 386.7 | | | (149.6) | | | (15.7) | | | 221.4 | |
Income tax provisions (benefits) | 73.0 | | | (38.0) | | | 1.6 | | | 36.6 | |
Results of operations (excluding Corporate segment) | $ | 313.7 | | | (111.6) | | | (17.3) | | | 184.8 | |
| | | | | | | |
Six months ended June 30, 2020 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 739.8 | | | 148.9 | | | 1.8 | | | 890.5 | |
Lease operating expenses | 295.0 | | | 58.0 | | | 0.8 | | | 353.8 | |
Severance and ad valorem taxes | 15.2 | | | 0.7 | | | — | | | 15.9 | |
Transportation, gathering and processing | 66.1 | | | 19.4 | | | — | | | 85.5 | |
Depreciation, depletion and amortization | 423.3 | | | 101.7 | | | 1.0 | | | 526.0 | |
Accretion of asset retirement obligations | 17.7 | | | 2.7 | | | — | | | 20.4 | |
Impairment of assets | 947.4 | | | — | | | 39.7 | | | 987.1 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | 7.7 | | | — | | | — | | | 7.7 | |
Geological and geophysical | 9.3 | | | 0.1 | | | 4.2 | | | 13.6 | |
Other exploration | 3.7 | | | 0.3 | | | 9.5 | | | 13.5 | |
| 20.7 | | | 0.4 | | | 13.7 | | | 34.8 | |
Undeveloped lease amortization | 9.9 | | | 0.2 | | | 4.6 | | | 14.7 | |
Total exploration expenses | 30.6 | | | 0.6 | | | 18.3 | | | 49.5 | |
Selling and general expenses | 11.3 | | | 9.8 | | | 3.9 | | | 25.0 | |
Other | (21.5) | | | (1.0) | | | (1.1) | | | (23.6) | |
Results of operations before taxes | (1,045.3) | | | (43.0) | | | (60.8) | | | (1,149.1) | |
Income tax provisions (benefits) | (206.2) | | | (16.6) | | | 0.5 | | | (222.3) | |
Results of operations (excluding Corporate segment) | $ | (839.1) | | | (26.4) | | | (61.3) | | | (926.8) | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Exploration and Production
Second quarter 20212022 vs. 20202021
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $491.5 million in the second quarter of 2022 compared to income of $194.7 million in the second quarter of 2021 compared to a loss of $143.1 million in the second quarter of 2020.2021. Results were $337.8$296.8 million favorable in the 20212022 quarter compared to the 20202021 period primarily due to higher revenues ($420.6328.9 million), lower leasedepreciation, depletion and amortization (DD&A, $26.3 million) and other operating expensesexpense ($26.3 million), lower impairment charge ($19.6 million), and general and administrative expenses (G&A: $2.337.6 million), partially offset by higher income tax expense ($87.676.4 million), otherand lease operating expense ($48.7 million) and depreciation, depletion and amortization ($4.219.0 million). Higher revenues were primarily due to higher commodity prices, higherpartially off-set by lower volumes. Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale volumes (dueShale. Lower other operating expense is primarily due to higher capital expenditures), and higher volumes in the U.S.lower unfavorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM), due to a 3.5% working interest acquisition acquisitions that occurred in the Lucius field. Lower lease operating expense was primarily attributable to well workers in the GOM in 2020. Lower G&A is due to cost reductions and lower headcount as a resultsecond quarter of restructuring (primarily closing the El Dorado and Calgary offices in 2020).2021. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher otherlease operating expense is primarily due to unfavorable markcost increases from inflationary pressures (mainly at our onshore businesses), higher severance taxes at Eagle Ford (due to market revaluation on contingent consideration (as a result of higher commodity prices) from prior Gulf of Mexico (GOM) acquisitions.and costs related to first production at the Khaleesi asset flowing to the King’s Quay facility.
Canadian E&P operations reported earnings of $47.2 million in the second quarter 2022 compared to income of $12.7 million in the second quarter 2021 compared to a loss of $19.5 million in the second quarter of 2020.2021. Results were favorable $32.2$34.5 million compared to the 20202021 period primarily due to higher revenuerevenues from production ($61.436.2 million) and lower depreciation and amortizationDD&A ($6.27.9 million), partially offset by higher tax expense ($18.2 million), higher lease operating expenses ($8.4 million), higher transportation, gathering, and processing expenses ($6.5 million), and lower other operating income ($2.112.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas pricesvolumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay.Montney. Lower depreciation expenseDD&A is due primarily to lower production volumes at Kaybob Duvernay due to normal well decline. Higher lease operating and transportation, gathering and processing costs areincome tax expense is a result of pre-tax profits principally due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.recovering oil price.
Other international E&P operations reported a loss from continuing operations of $3.5 million in the second quarter of 2022 compared to a loss of $10.4 million in the second quarter of 2021 compared to a loss of $9.0 million in the second quarter of 2020.2021. The result was $1.4$6.9 million unfavorablefavorable in the 20212022 period versus 20202021 primarily due to higher exploration expenses and income tax expense.revenue from Brunei.
Six months 20212022 vs. 20202021
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $744.4 million in the first six months of 2022 compared to earnings of $313.7 million in the first six months of 2021 compared to a loss of $839.1 million in the first six months of 2020.2021. Results were $1,152.8$430.7 million favorable in the 2021 quarter2022 period compared to the 20202021 period, primarily due to no impairment charges in the current period (2020: $947.4 million). Further, the change year over year is driven by higher revenues ($399.4 million), lower depreciation, depletion and amortization (DD&A: $93.7 million), lower lease operating expenses (LOE: $88.4 million), lower transportation, gathering, and processing charges ($4.0546.0 million) and lower GDD&A ($0.549.4 million), partially offset by higher income tax expense ($279.2106.1 million) and higher other operating expense ($115.943.7 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of decreased oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 20212022 compared to 2020.2021, offset by lower oil sales and production volumes driven primarily by a focused effort to reduce capital expenditures to prioritize corporate debt reduction. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to higher Gulf of Mexico workover costs in the prior year at Cascade ($49.3 million)lower production volumes and Dalmatian ($20.5 million).lower rates driven by positive reserve revisions. Higher income tax expense is a result of higher pre-tax profits principally due to the recovering oil price and lower DD&A and LOE.income. Higher other operating expense is primarily due to ana higher unfavorable mark to market revaluation on contingent consideration ($76.7129.8 million; as a result of higher commodity prices) from prior Gulf of Mexico (GOM)GOM acquisitions.
Canadian E&P operations reported earnings of $69.9 million in the first six months of 2022 compared to a loss of $111.6 million in the first six months of 2021 compared to a loss of $26.4 million in the first six months quarter of 2020.2021. Results were $85.2$181.5 million unfavorablefavorable compared to the 2020 period primarily due to2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and prior to the subsequent sanctioning of an asset life extension project in the third quarter of 2021. The current period, partially offset byyear results also include higher revenue from production ($75.761.5 million), higher income tax benefit ($21.4 million), and lower DD&A ($13.418.5 million). The impairment charge in the current year is due to the status, including agreements with the partners, of offset by higher income tax expense ($62.6 million), lease operating expenses ($7.2 million) and production plans at Terra Nova as of June 30, 2021. During the second quarter, partners continued to negotiate on an agreement to restructure the Terra Nova project ownershiptransportation, gathering and renew the asset life extension project.processing costs ($4.8 million). Higher revenue is primarily attributable to higher realized prices (oil and condensate, natural gas pricesand NGLs). Lower DD&A is primarily due to lower production volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay.Duvernay due to normal well decline. Higher income tax benefitexpense is a result of a higher pre-tax loss driven byincome principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity. Higher capacity is expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss of $47.7 million in the first six months of 2022 compared to a loss of $17.3 million in the prior year. Results were $30.4 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
charge. Lower DD&A is a result of lower sales volume at Kaybob Duvernay following reduced capital expenditures throughout 2020.
Other international E&P operations reported a loss of $17.3 millionexploration well in block SEAL-M-428 in the first six months of 2021 compared to a loss of $61.3 million in the prior year. ResultsSergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were $44.0 million favorable compared to the 2020 period primarily due to an impairment charge of $39.7 million in the prior year.
discovered.
Corporate
Second quarter 20212022 vs. 20202021
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative commodity contracts (typically forwardinstruments (forward swaps to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a net loss of $223.9 million in the second quarter 2021 compared to net loss of $151.6 million in the 2020 quarter. The $72.3 million unfavorable variance is principally due to higher losses on forward swap commodity contracts in 2021 compared to the 2020 period (2021: $226.2 million loss; 2020: $75.9 million loss). This is partially offset by lower restructuring charges ($41.4 million), higher tax benefits ($23.2 million), lower G&A ($6.1 million) and lower DD&A ($2.3 million). Losses on forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with a fixed price. Lower restructuring charges and G&A expenditures are due to the 2020 cost reduction efforts which included closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.
Six months 2021 vs. 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative commodity contracts (typically forward swapscollars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $478.8$124.8 million in the first six monthssecond quarter of 20212022 compared to earningsa loss of $99.8$223.9 million in the first six monthssecond quarter of 2020.2021. The $578.6$99.1 million unfavorablefavorable variance is primarilyprincipally due to realized and unrealizedlower losses on forward swap commodity contractsderivative instruments in 20212022 ($123.2 million) compared to gains in 2020 (2021: $440.6the 2021 period (2022: $103.1 million loss; 2020: $324.82021: $226.2 million gain), and higher interest expense ($50.7 million)loss), partially offset by higher tax benefitsexpense ($171.9 million), lower restructuring charges ($41.4 million), lower G&A ($14.6 million) and lower DD&A ($5.027.3 million). Realized and unrealized losses on forward swap commodity contractsderivative instruments are due to higher market (West Texas Intermediate)an increase in oil prices for current (realized) and future (unrealized) periods whereby the contract providesswap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of June 30, 2021,2022, the average forward NYMEX WTI price for the remainder of 2021 was $71.80 and for 2022 was $66.38$100.49 (versus swap contract fixed hedge pricesprice of $42.77 and $44.88, respectively)$44.88). Interest charges are higher in 2021primarily due an early redemption premium incurred byThe swap contracts provide the Company uponwith a fixed price and the early retirement of the notes originally due Junecollar contracts provide for a minimum (floor) and December 2022.a maximum (ceiling) price. Higher income tax benefits arebenefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on forward swap commodity contracts. Lower restructuringderivative instruments.
Six 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 $421.1 million in the first six months of 2022 compared to a loss of $478.8 million in the first six months of 2021. The $57.7 million favorable variance is primarily due to lower interest expense ($60.1 million) and lower losses on derivative instruments in 2022 ($16.8 million) compared to 2021 (2022: $423.8 million loss; 2021: $440.6 million loss), partially offset by lower tax benefits ($19.5 million). Interest charges are lower in the first six months of 2022primarily due to lower debt redemption premiums ($3.4 million in 2022; $34.2 million in 2021) incurred by the Company and G&A expenditureslower overall debt. In the first six months of 2022 the Company redeemed $200.0 million of notes compared to the 2021 redemption of $576.4 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 2020 cost reduction efforts which included closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta,swap contracts provide the Company with a fixed price and consolidating all worldwide staff activities to its existing office location in Houston, Texas.the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of June 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $100.49 (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
Second quarter 20212022 vs. 20202021
Total hydrocarbon production from continuing operations averaged 182,050173,173 barrels of oil equivalent per day in the second quarter of 2021,2022, which represented a 1% increase fromwas 5% lower than the 179,506182,050 barrels per day produced in second quarter 2020.2021. The increasedecrease in production volumes is principally due to increased productionan ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders; partially offset by first oil from the Khaleesi, Mormont, Samurai field development project in the U.S. offset by lower production in Canada.second quarter.
Average crude oil and condensate production from continuing operations was 98,661 barrels per day in the second quarter of 2022 compared to 109,327 barrels per day in the second quarter of 2021 compared to 108,712 barrels per day in the second quarter2021. The decrease of 2020. The increase of 61510,666 barrels per day was associated with higher Eagle Ford Shale production (3,267 barrels per day higher at Karnes due to 2021 capital expenditures in this area), higherlower volumes in the Gulf of Mexico (1,466(5,041 barrels per dayday) principally due to a 3.5% working interest acquisition in Lucius field),the focused effort to reduce capital expenditures and several planned downtime events at St. Malo and Chinook, partially offset by first production from the first four wells at the Khaleesi, Mormont, Samurai development. Canada production is lower volumes in Canada (4,477(1,700 barrels per day lowerday) primarily attributable to Kaybob Duvernay well decline).decline and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (4,949 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged $65.57$109.25 per barrel in the second quarter 20212022 compared to $23.03$65.57 per barrel in the 20202021 period, an increase of 185%67% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 11,25210,950 barrels per day in the second quarter 20212022 compared to 11,54011,252 barrels per day in the 20202021 period. The average sales price for U.S. NGL was $39.37 per barrel in the 2022 quarter compared to $22.18 per barrel in the 2021 quarter compared to $7.67 per barrel in 2020.2021. The average sales price for NGL in Canada was $30.63$63.99 per barrel in the 20212022
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
quarter compared to $13.78$30.63 per barrel in 2020.2021. 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 369381.4 million cubic feet per day (MMCFD) in the second quarter 20212022 compared to 356368.8 MMCFD in 2020.2021. The increase of 1312.5 MMCFD was a result of higher volumes in Canada (8(20.8 MMCFD), partially offset by lower volumes in the Gulf of Mexico (3 MMCFD) and in the Eagle Ford Shale (2(8.3 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 1015 new wells at Tupper Montney in the second quarter of 2021. Higher volumes in the Gulf of Mexico are principally due to higher natural gas volumes at Lucius and Neidermeyer.2022.
Natural gas prices for the total Company averaged $2.34$3.90 per thousand cubic feet (MCF) in the 20212022 quarter, versus $1.54$2.34 per MCF average in the same quarter of 2020.2021. Average natural gas prices in the U.S. and Canada in the quarter were $2.61$7.37 and $2.23$2.78 per MCF, respectively.
Six months 20212022 vs. 20202021
Total hydrocarbon production from all E&P continuing operationsExploration and Production averaged 173,762161,579 barrels of oil equivalent per day in the first six months of 2021,2022, which represented a 8%7.0% decrease from the 189,350173,762 barrels per day produced in the first six months of 2020.2021. The decrease in production is principally due to loweran ongoing focused effort to reduce capital expenditures throughoutthat began in 2020 to support generating positive free cashflow.prioritize corporate debt reduction and return funds to shareholders.
Average crude oil and condensate production from continuing operations was 91,154 barrels per day in the first six months of 2022 compared to 103,434 barrels per day in the first six months of 2021 compared to 115,396 barrels per day in the first six months of 2020.2021. The decrease of 11,96212,280 barrels per day was principally due to lower Gulf of Mexico production (6,439(7,064 barrels per day) due to the focused effort to reduce capital expenditures and several planned downtime events including a facility upgrade which lowered current production at Neidermeyer and Marmalard as well as maintenance operations at St. Malo, Front Runner, Habanero and Chinook. Canada production is lower (2,434 barrels per day) due to normal field decline at Kaybob and temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 (these operational issues are now resolved), offset by higher second quarterHibernia. Eagle Ford Shale production at Lucius.is lower (3,400 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged $62.14$102.86 per barrel in the first six months of 20212022 compared to $35.65$62.14 per barrel in the 20202021 period, an increase of 74%65.5% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,55210,150 barrels per day in the first six months of 20212022 compared to 12,59710,552 barrels per day in the 20202021 period. The average sales price for U.S. NGL was $40.00 per barrel in 2022 compared to $22.41 per barrel in 2021 compared to $8.62 per barrel in 2020.2021. The average sales price for NGL in Canada was $59.23 per barrel in 2022 compared to $33.34 per barrel in 2021 compared to $15.04 per barrel in 2020.2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.
Natural gas salesproduction volumes from continuing operations averaged 359361.7 million cubic feet per day (MMCFD) in the first six months of 20212022 compared to 368358.7 MMCFD in 2020.2021. The decreaseincrease of 93.0 MMCFD was primarily the result of higher volumes in Canada 12.7 MMCFD) and Eagle Ford Shale (2.7 MMCFD), partially offset by the Gulf of Mexico (12.4 MMCFD). The higher natural gas volumes in Canada was the result of lower volumes in Eagle Ford (4 MMCFD), the Gulf of Mexico (3 MMCFD) and Canada (2 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields (these operational issues are now resolved). Lower volumes in Canada and Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting the Eagle Ford Shalenew wells on production in the first quarterhalf of 2021.
the year. Natural gas prices for the total Company averaged $2.44$3.54 per thousand cubic feet (MCF) in the first six months of 2021,2022, versus $1.64$2.44 per MCF average in the same period of 2020.2021. Average realized natural gas prices in the U.S. and Canada in the quarter were $2.97$6.26 per MCF and $2.25,$2.66 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 2625 and 27.26.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table containsreports hydrocarbons produced during the three-month and six-month periods ended June 30, 20212022 and 2020.2021.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
Barrels per day unless otherwise noted | Barrels per day unless otherwise noted | 2021 | | 2020 | | 2021 | | 2020 | Barrels per day unless otherwise noted | 2022 | | 2021 | | 2022 | | 2021 |
Continuing operations | | | | | | | | | |
| Net crude oil and condensate | Net crude oil and condensate | | Net crude oil and condensate | | | | | | | |
United States | United States | Onshore | 31,253 | | | 27,986 | | | 26,734 | | | 29,510 | | United States | Onshore | 26,304 | | | 31,253 | | | 23,334 | | | 26,734 | |
| | Gulf of Mexico 1 | 68,468 | | | 67,002 | | | 66,427 | | | 72,866 | | | Gulf of Mexico 1 | 63,427 | | | 68,468 | | | 59,363 | | | 66,427 | |
Canada | Canada | Onshore | 5,558 | | | 7,872 | | | 5,921 | | | 7,353 | | Canada | Onshore | 4,419 | | | 5,558 | | | 4,400 | | | 5,921 | |
| | Offshore | 3,689 | | | 5,852 | | | 4,137 | | | 5,495 | | | Offshore | 3,128 | | | 3,689 | | | 3,224 | | | 4,137 | |
Other | Other | | 359 | | | — | | | 215 | | | 172 | | Other | | 1,383 | | | 359 | | | 833 | | | 215 | |
Total net crude oil and condensate - continuing operations | Total net crude oil and condensate - continuing operations | 109,327 | | | 108,712 | | | 103,434 | | | 115,396 | | Total net crude oil and condensate - continuing operations | 98,661 | | | 109,327 | | | 91,154 | | | 103,434 | |
Net natural gas liquids | Net natural gas liquids | | | | | | | | | Net natural gas liquids | | | | | | | | |
United States | United States | Onshore | 5,327 | | | 5,303 | | | 4,634 | | | 5,444 | | United States | Onshore | 5,178 | | | 5,327 | | | 5,006 | | | 4,634 | |
| | Gulf of Mexico 1 | 4,763 | | | 5,219 | | | 4,721 | | | 5,944 | | | Gulf of Mexico 1 | 4,913 | | | 4,763 | | | 4,223 | | | 4,721 | |
Canada | Canada | Onshore | 1,162 | | | 1,018 | | | 1,197 | | | 1,209 | | Canada | Onshore | 859 | | | 1,162 | | | 921 | | | 1,197 | |
Total net natural gas liquids - continuing operations | Total net natural gas liquids - continuing operations | 11,252 | | | 11,540 | | | 10,552 | | | 12,597 | | Total net natural gas liquids - continuing operations | 10,950 | | | 11,252 | | | 10,150 | | | 10,552 | |
Net natural gas – thousands of cubic feet per day | Net natural gas – thousands of cubic feet per day | | | | | | | | Net natural gas – thousands of cubic feet per day | | | | | | | |
United States | United States | Onshore | 29,653 | | | 27,697 | | | 25,855 | | | 29,830 | | United States | Onshore | 29,651 | | | 29,653 | | | 28,512 | | | 25,855 | |
| | Gulf of Mexico 1 | 71,962 | | | 68,717 | | | 72,308 | | | 75,333 | | | Gulf of Mexico 1 | 63,703 | | | 71,962 | | | 59,902 | | | 72,308 | |
Canada | Canada | Onshore | 267,210 | | | 259,108 | | | 260,491 | | | 262,978 | | Canada | Onshore | 288,019 | | | 267,210 | | | 273,237 | | | 260,491 | |
Total net natural gas - continuing operations | Total net natural gas - continuing operations | 368,825 | | | 355,522 | | | 358,654 | | | 368,141 | | Total net natural gas - continuing operations | 381,373 | | | 368,825 | | | 361,651 | | | 358,654 | |
Total net hydrocarbons - continuing operations including NCI 2,3 | Total net hydrocarbons - continuing operations including NCI 2,3 | 182,050 | | | 179,506 | | | 173,762 | | | 189,350 | | Total net hydrocarbons - continuing operations including NCI 2,3 | 173,173 | | | 182,050 | | | 161,579 | | | 173,762 | |
Noncontrolling interest | Noncontrolling interest | | | | | | | | | Noncontrolling interest | | | | | | | | |
Net crude oil and condensate – barrels per day | Net crude oil and condensate – barrels per day | (9,800) | | | (10,719) | | | (9,489) | | | (11,370) | | Net crude oil and condensate – barrels per day | (7,962) | | | (9,800) | | | (8,044) | | | (9,489) | |
Net natural gas liquids – barrels per day | Net natural gas liquids – barrels per day | (370) | | | (443) | | | (362) | | | (501) | | Net natural gas liquids – barrels per day | (319) | | | (370) | | | (303) | | | (362) | |
Net natural gas – thousands of cubic feet per day | (4,024) | | | (4,059) | | | (4,091) | | | (4,575) | | |
Net natural gas – thousands of cubic feet per day 2 | | Net natural gas – thousands of cubic feet per day 2 | (3,097) | | | (4,024) | | | (2,845) | | | (4,091) | |
Total noncontrolling interest | Total noncontrolling interest | (10,841) | | | (11,839) | | | (10,533) | | | (12,634) | | Total noncontrolling interest | (8,797) | | | (10,841) | | | (8,821) | | | (10,533) | |
Total net hydrocarbons - continuing operations excluding NCI 2,3 | Total net hydrocarbons - continuing operations excluding NCI 2,3 | 171,209 | | | 167,667 | | | 163,229 | | | 176,716 | | Total net hydrocarbons - continuing operations excluding NCI 2,3 | 164,376 | | | 171,209 | | | 152,758 | | | 163,229 | |
| |
1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table containsreports the weighted average sales prices excluding transportation cost deduction and sales of purchased natural gas for the three-month and six-month periods ended June 30, 20212022 and 2020.Comparative periods are conformed to current presentation.2021.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Weighted average Exploration and Production sales prices | Weighted average Exploration and Production sales prices | | | | | | | | Weighted average Exploration and Production sales prices | | | | | | | |
Continuing operations | Continuing operations | | Continuing operations | |
Crude oil and condensate – dollars per barrel | Crude oil and condensate – dollars per barrel | | Crude oil and condensate – dollars per barrel | |
United States | United States | Onshore | 64.55 | | | 21.42 | | | 61.60 | | | 34.59 | | United States | Onshore | $ | 110.66 | | | 64.55 | | | $ | 103.39 | | | 61.60 | |
| | Gulf of Mexico 1 | 65.95 | | | 24.77 | | | 62.56 | | | 37.00 | | | Gulf of Mexico 1 | 109.55 | | | 65.95 | | | 102.76 | | | 62.56 | |
Canada 2 | Canada 2 | Onshore | 60.69 | | | 16.09 | | | 56.55 | | | 26.09 | | Canada 2 | Onshore | 100.51 | | | 60.69 | | | 96.84 | | | 56.55 | |
| | Offshore | 73.20 | | | 20.48 | | | 67.51 | | | 35.28 | | | Offshore | 115.65 | | | 73.20 | | | 113.46 | | | 67.51 | |
Other | Other | | — | | | — | | | — | | | 63.51 | | Other | | 86.51 | | | — | | | 86.51 | | | — | |
Natural gas liquids – dollars per barrel | Natural gas liquids – dollars per barrel | | Natural gas liquids – dollars per barrel | |
United States | United States | Onshore | 19.75 | | | 8.03 | | | 20.38 | | | 9.45 | | United States | Onshore | 38.29 | | | 19.75 | | | 38.30 | | | 20.38 | |
| | Gulf of Mexico 1 | 24.84 | | | 7.29 | | | 24.36 | | | 7.85 | | | Gulf of Mexico 1 | 40.46 | | | 24.84 | | | 41.95 | | | 24.36 | |
Canada 2 | Canada 2 | Onshore | 30.63 | | | 13.78 | | | 33.34 | | | 15.04 | | Canada 2 | Onshore | 63.99 | | | 30.63 | | | 59.23 | | | 33.34 | |
Natural gas – dollars per thousand cubic feet | Natural gas – dollars per thousand cubic feet | | Natural gas – dollars per thousand cubic feet | |
United States | United States | Onshore | 2.54 | | | 1.62 | | | 2.84 | | | 1.74 | | United States | Onshore | 7.06 | | | 2.54 | | | 5.89 | | | 2.84 | |
| | Gulf of Mexico 1 | 2.64 | | | 1.71 | | | 3.01 | | | 1.87 | | | Gulf of Mexico 1 | 7.52 | | | 2.64 | | | 6.43 | | | 3.01 | |
Canada 2 | Canada 2 | Onshore | 2.23 | | | 1.49 | | | 2.25 | | | 1.55 | | Canada 2 | Onshore | 2.78 | | | 2.23 | | | 2.66 | | | 2.25 | |
| | | | | | |
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $686.3$959.2 million for the first six months of 20212022 compared to $369.4$686.3 million during the same period in 2020.2021. The increased cash from operating activities of $273.0 million is primarily attributable to higher revenue from sales to customersproduction ($465.1629.5 million), lower lease operating expense ($80.2 million), loweroffset by the timing of working capital settlements ($25.2 million)148.2 million; primarily higher revenue received in cash following the end of the quarter), and lower general and administrative expensehigher realized losses on derivative instruments ($17.3 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $156.3 million; 2020: realized gain of $150.9167.2 million).
Cash Required by Investing Activities
Net cash required by investing activities was $193.7$599.3 million for the first six months of 20212022 compared to $589.2net cash provided by investing activities of $193.7 million during the same period in 2020.2021. In the second quarter of 2022, the Company acquired an 11.0% additional working interest in Kodiak for $46.5 million (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were $463.0$552.8 million and $589.2$422.8 million in the first six months of 2022 and 2021, and 2020, respectively. These amounts include $17.7 million and $51.6 million used to fund the developmentThe first quarter of 2021 included sales proceeds for the King’s Quay FPS in the first six months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS$267.7 million, which was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company for previously incurred capital expenditures. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay..
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
Total accrual basis capital expenditures were as follows:
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
(Millions of dollars) | (Millions of dollars) | 2021 | | 2020 | (Millions of dollars) | 2022 | | 2021 |
Capital Expenditures | Capital Expenditures | | | | Capital Expenditures | | | |
Exploration and production | Exploration and production | $ | 449.4 | | | 550.2 | | Exploration and production | $ | 611.4 | | | 449.4 | |
Corporate | Corporate | 8.8 | | | 7.4 | | Corporate | 10.5 | | | 8.8 | |
Total capital expenditures | Total capital expenditures | $ | 458.2 | | | 557.6 | | Total capital expenditures | $ | 621.9 | | | 458.2 | |
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
(Millions of dollars) | (Millions of dollars) | 2021 | | 2020 | (Millions of dollars) | 2022 | | 2021 |
Property additions and dry hole costs per cash flow statements | $ | 445.3 | | | 537.6 | | |
Property additions and dry hole costs per cash flow statements 1 | | Property additions and dry hole costs per cash flow statements 1 | $ | 552.8 | | | 422.8 | |
Property additions King's Quay per cash flow statements | Property additions King's Quay per cash flow statements | 17.7 | | | 51.6 | | Property additions King's Quay per cash flow statements | — | | | 17.7 | |
| Acquisition of oil and gas properties 1 | | Acquisition of oil and gas properties 1 | 46.5 | | | 22.5 | |
Geophysical and other exploration expenses | Geophysical and other exploration expenses | 12.4 | | | 23.0 | | Geophysical and other exploration expenses | 16.3 | | | 12.4 | |
Capital expenditure accrual changes and other | Capital expenditure accrual changes and other | (17.2) | | | (54.6) | | Capital expenditure accrual changes and other | 6.3 | | | (17.2) | |
Total capital expenditures | Total capital expenditures | $ | 458.2 | | | 557.6 | | Total capital expenditures | $ | 621.9 | | | 458.2 | |
Capital1 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 20212022 compared to 2020 have decreased as a result2021 is primarily attributable to expenditures related to the Kodiak acquisition in Gulf of Mexico ($46.5 million), Cutthroat-1 exploration well in Brazil ($24.3 million), capital expenditure reductions to support generating positive free cash flow.invested at the Khaleesi, Mormont, Samurai field development project and higher development drilling activities in Tupper Montney and Kaybob Duvernay assets.
Cash Used in/ ProvidedRequired by Financing Activities
Net cash required by financing activities was $386.7$447.5 million for the first six months of 20212022 compared to net cash provided by financing activities of $60.0$386.7 million during the same period in 2020.2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024 ($200.0 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 ($94.9 million), and cash dividends to shareholders of $0.325 per share ($50.5 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. This amount represents a 43% increase from the first quarter of 2022 and a 100% increase from fourth quarter 2021. Additionally, the Company announced a capital allocation framework, approved by the Board of Directors, that allows for further capital to be returned to the shareholders beyond the current dividend, while still advancing the Company’s long-term debt reduction goals. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.
As of June 30, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,572.4 million available on its committed RCF.
In first six months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ($576.4 million)million), early redemption cost (make whole payment) of the notes due 2022 ($34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($75.2 million), and cash dividends to shareholders ($38.6 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).
As of June 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,569.0 million available on its committed RCF.
In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($370.0 million), offset by repayments on the revolving credit facility ($200.0 million), cash dividends to shareholders ($57.6 million), and distributions to the NCI ($32.4 million).
Working Capital
Working capital (total current assets less total current liabilities, – excluding assets and liabilities held for sale) atas of June 30, 20212022 was a deficit of $395.5$566.9 million, $366.1 $268.0 million lower than December 31, 2020,2021, with the decrease primarilyprimarily attributable to higher accounts payable ($337.0286.9 million), higher other accrued liabilities ($170.9122.6 million), a lower cash balance ($89.2 million) and higher operating lease liabilities ($63.728.5 million), partlypartially offset by a higher cash balance ($107.5 million) and higher accounts receivable ($104.5263.9 million). Higher accounts payable is primarily due to the increase in unrealized losses on crude contracts maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 GOM acquisitions) and short-term abandonment liabilities associated with Terra Nova and Cottonwood assets. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS.
Capital Employed
At June 30, 2021, long-term debt of $2,762.9 million had decreased by $225.2 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 ($576.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
payable is primarily due to the increase in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the remainder of 2022 as well as higher trade payables principally related to the Khaleesi, Mormont and Samurai field development project. Higher other accrued liabilities are associated with higher contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project. Higher accounts receivable are principally due to higher crude oil pricing.
Capital Employed
At June 30, 2022, long-term debt of $2,267.9 million had decreased by $197.5 million compared to December 31, 2021, primarily as a result of the partial redemption of notes due 2024 ($200.0 million). The total of the fixed-rate notes had a weighted average maturity of 7.4 years and a weighted average coupon of 6.2%.
A summary of capital employed at June 30, 20212022 and December 31, 20202021 follows.
| | | June 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
(Millions of dollars) | (Millions of dollars) | Amount | | % | | Amount | | % | (Millions of dollars) | Amount | | % | | Amount | | % |
Capital employed | Capital employed | | | | | | | | Capital employed | | | | | | | |
Long-term debt | Long-term debt | $ | 2,762.9 | | | 41.6 | % | | $ | 2,988.1 | | | 41.5 | % | Long-term debt | $ | 2,267.9 | | | 34.5 | % | | $ | 2,465.4 | | | 37.2 | % |
Murphy shareholders' equity | Murphy shareholders' equity | 3,880.6 | | | 58.4 | % | | 4,214.3 | | | 58.5 | % | Murphy shareholders' equity | 4,312.8 | | | 65.5 | % | | 4,157.3 | | | 62.8 | % |
Total capital employed | Total capital employed | $ | 6,643.5 | | | 100.0 | % | | $ | 7,202.4 | | | 100.0 | % | Total capital employed | $ | 6,580.7 | | | 100.0 | % | | $ | 6,622.7 | | | 100.0 | % |
Cash and invested cash are maintained in several operating locations outside the United States. AtAs of June 30, 2021,2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $121.9$82.7 million in CanadaCanada. In addition, approximately $21.8 million of cash was held in Brunei, $17.7 million of cash was held in Mexico and $8.4$13.6 million of cash was held in Brunei.Brazil. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements
Outlook
As discussed in the Summary section on page 23,22, several factors have continued to contribute to the higher average crude oil prices continued to recoverprice during the second quarter, of 2021 versuswhich directly impacts the second quarter of 2020Company’s product revenue from sales (Q2 2020 WTI: $27.85;2022; $108.41 Q1 2022; $94.29; Q2 2021 WTI:2021: $66.07). Currently, recessionary concerns have placed some downward pressure on average crude oil prices. As of close on August 3, 2021,2, 2022, the NYMEX WTI forward curve price for the remainder of 20212022 and 20222023 were $69.71lower at $92.82 and $65.34$86.14 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and OPEC+ decisions)production sector investment, inflation and the Russia/Ukraine conflict) may have on future commodity pricing.prices. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the third quarter, production is expected to average between 162180.0 and 170188.0 MBOEPD, excluding NCI.noncontrolling interest (NCI).
The Company’s capital expenditure spend for 20212022 is expected to be between $685.0$900.0 million and $715.0 million.$950.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures and other expenditures will beare routinely reviewed during 2021 and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarilyplans to fund its remaining capital program in 20212022 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt. In the third quarter of 2021, the Company announced the redemption of $150.0 million in aggregate principal amount of its 6.875% notes due 2024.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company continues to monitor the effects
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
As of August 3, 2021,2, 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 | | Commodity | | Type | | Volumes (Bbl/d) | | Price (USD/Bbl) | | Remaining Period |
Area | Area | | Start Date | | End Date | Area | | Start Date | | End Date |
United States | United States | | WTI ¹ | | Fixed price derivative swap | | 45,000 | | | $42.77 | | | 7/1/2021 | | 12/31/2021 | United States | | WTI² | | Fixed price derivative swap | | 20,000 | | | $44.88 | | | 7/1/2022 | | 12/31/2022 |
United States | | WTI ¹ | | Fixed price derivative swap | | 20,000 | | | $44.88 | | | 1/1/2022 | | 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 | | | 7/1/2022 | | 12/31/2022 |
1 West Texas Intermediate
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
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| | | | | | Volumes (MMcf/d) | | Price (CAD/Mcf)Price/Mcf | | Remaining Period |
Area | | Commodity | | Type | | | | Start Date | | End Date |
MontneyCanada | | Natural Gas | | Fixed price forward sales at AECO | | 241247 | | | C$2.572.34 | | 7/1/20212022 | | 12/10/31/20212022 |
MontneyCanada | | Natural Gas | | Fixed price forward sales at AECO | | 231266 | | | C$2.42 | | 1/1/2022 | | 1/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 221 | | | C$2.41 | | 2/1/2022 | | 4/30/2022 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 250 | | | C$2.40 | | 5/1/2022 | | 5/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 292 | | | C$2.39 | | 6/1/2022 | | 10/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 311 | | | C$2.402.36 | | 11/1/2022 | | 12/31/2022 |
MontneyCanada | | Natural Gas | | Fixed price forward sales at AECO | | 294269 | | | C$2.382.36 | | 1/1/2023 | | 3/31/2023 |
MontneyCanada | | Natural Gas | | Fixed price forward sales at AECO | | 275250 | | | C$2.372.35 | | 4/1/2023 | | 12/31/2023 |
MontneyCanada | | Natural Gas | | Fixed price forward sales at AECO | | 185162 | | | C$2.412.39 | | 1/1/2024 | | 12/31/2024 |
Canada | | Natural Gas | | Fixed price forward sales | | 45 | | | US$2.05 | | 7/1/2022 | | 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 20202021 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 3736 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at June 30, 2021,2022, covering certain future U.S. crude oil sales volumes in 2021 andfor 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 $106.9$78.5 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 June 30, 2021.2022.
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 June 30, 2021,2022, 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.
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 20202021 Form 10-K filed on February 26, 2021.25, 2022. The Company has not identified any additional risk factors not previously disclosed in its 20202021 Form 10-K report.
ITEM 6. EXHIBITS
The Exhibit Index on page 3938 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
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/ CHRISTOPHERPAUL D. HULSEVAUGHAN |
| | ChristopherPaul D. HulseVaughan |
| | Vice President and Controller |
| | (Chief Accounting Officer and Duly Authorized Officer) |
August 5, 20214, 2022
(Date)
EXHIBIT INDEX
The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.
| | | | | | | | | | | |
Exhibit No. | | | Incorporated by Reference to the Indicated Filing by Murphy Oil Corporation |
| | | |
10.26 | | | Exhibit A to definitive proxy statement filed March 26, 2021 |
*10.27 | | | |
*31.1 | | | |
*31.2 | | | |
*32 | | | |
101. INS | | XBRL Instance Document | |
101. SCH | | XBRL Taxonomy Extension Schema Document | |
101. CAL | | XBRL Taxonomy Extension Calculation Linkbase Document | |
101. DEF | | XBRL Taxonomy Extension Definition Linkbase Document | |
101. LAB | | XBRL Taxonomy Extension Labels Linkbase Document | |
101. PRE | | XBRL Taxonomy Extension Presentation Linkbase | |