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 September 30, 20202021
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 October 31, 20202021 was 153,598,625154,459,128.
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) | September 30, 2020 | | December 31, 2019 | (Thousands of dollars) | September 30, 2021 | | December 31, 2020 |
ASSETS | ASSETS | | | | ASSETS | | | |
Current assets | Current assets | | Current assets | |
Cash and cash equivalents | Cash and cash equivalents | $ | 219,636 | | | 306,760 | | Cash and cash equivalents | $ | 505,067 | | | 310,606 | |
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019 | 279,149 | | | 426,684 | | |
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020 | | Accounts receivable, less allowance for doubtful accounts of $1,605 in 2021 and 2020 | 186,683 | | | 262,014 | |
Inventories | Inventories | 67,856 | | | 76,123 | | Inventories | 57,411 | | | 66,076 | |
Prepaid expenses | Prepaid expenses | 58,099 | | | 40,896 | | Prepaid expenses | 40,583 | | | 33,860 | |
Assets held for sale | Assets held for sale | 108,916 | | | 123,864 | | Assets held for sale | 40,987 | | | 327,736 | |
Total current assets | Total current assets | 733,656 | | | 974,327 | | Total current assets | 830,731 | | | 1,000,292 | |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,102,285 in 2020 and $9,333,646 in 2019 | 8,592,834 | | | 9,969,743 | | |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020 | | Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,268,101 in 2021 and $11,455,305 in 2020 | 8,112,093 | | | 8,269,038 | |
Operating lease assets | Operating lease assets | 765,484 | | | 598,293 | | Operating lease assets | 918,719 | | | 927,658 | |
Deferred income taxes | Deferred income taxes | 347,053 | | | 129,287 | | Deferred income taxes | 442,212 | | | 395,253 | |
Deferred charges and other assets | Deferred charges and other assets | 30,324 | | | 46,854 | | Deferred charges and other assets | 27,101 | | | 28,611 | |
| Total assets | Total assets | $ | 10,469,351 | | | 11,718,504 | | Total assets | $ | 10,330,856 | | | 10,620,852 | |
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 | $ | 646 | | | — | |
Accounts payable | Accounts payable | $ | 295,398 | | | 602,096 | | Accounts payable | 615,436 | | | 407,097 | |
Income taxes payable | Income taxes payable | 17,813 | | | 19,049 | | Income taxes payable | 18,035 | | | 18,018 | |
Other taxes payable | Other taxes payable | 23,755 | | | 18,613 | | Other taxes payable | 26,997 | | | 22,498 | |
Operating lease liabilities | Operating lease liabilities | 100,169 | | | 92,286 | | Operating lease liabilities | 157,294 | | | 103,758 | |
Other accrued liabilities | Other accrued liabilities | 157,574 | | | 197,447 | | Other accrued liabilities | 316,205 | | | 150,578 | |
Liabilities associated with assets held for sale | Liabilities associated with assets held for sale | 14,677 | | | 13,298 | | Liabilities associated with assets held for sale | — | | | 14,372 | |
Total current liabilities | Total current liabilities | 609,386 | | | 942,789 | | Total current liabilities | 1,134,613 | | | 716,321 | |
Long-term debt, including capital lease obligation | 2,987,057 | | | 2,803,381 | | |
Long-term debt, including finance lease obligation | | Long-term debt, including finance lease obligation | 2,613,703 | | | 2,988,067 | |
Asset retirement obligations | Asset retirement obligations | 856,856 | | | 825,794 | | Asset retirement obligations | 797,627 | | | 816,308 | |
Deferred credits and other liabilities | Deferred credits and other liabilities | 635,980 | | | 613,407 | | Deferred credits and other liabilities | 723,732 | | | 680,580 | |
Non-current operating lease liabilities | Non-current operating lease liabilities | 686,516 | | | 521,324 | | Non-current operating lease liabilities | 781,114 | | | 845,088 | |
Deferred income taxes | Deferred income taxes | 179,511 | | | 207,198 | | Deferred income taxes | 166,120 | | | 180,341 | |
| Total liabilities | Total liabilities | 5,955,306 | | | 5,913,893 | | Total liabilities | 6,216,909 | | | 6,226,705 | |
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 2020 and 195,089,269 shares in 2019 | 195,101 | | | 195,089 | | |
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 2021 and 195,100,628 shares in 2020 | | Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2021 and 195,100,628 shares in 2020 | 195,101 | | | 195,101 | |
Capital in excess of par value | Capital in excess of par value | 936,318 | | | 949,445 | | Capital in excess of par value | 921,227 | | | 941,692 | |
Retained earnings | Retained earnings | 5,560,673 | | | 6,614,304 | | Retained earnings | 5,069,578 | | | 5,369,538 | |
Accumulated other comprehensive loss | Accumulated other comprehensive loss | (657,995) | | | (574,161) | | Accumulated other comprehensive loss | (580,174) | | | (601,333) | |
Treasury stock | Treasury stock | (1,690,661) | | | (1,717,217) | | Treasury stock | (1,656,224) | | | (1,690,661) | |
Murphy Shareholders' Equity | Murphy Shareholders' Equity | 4,343,436 | | | 5,467,460 | | Murphy Shareholders' Equity | 3,949,508 | | | 4,214,337 | |
Noncontrolling interest | Noncontrolling interest | 170,609 | | | 337,151 | | Noncontrolling interest | 164,439 | | | 179,810 | |
Total equity | Total equity | 4,514,045 | | | 5,804,611 | | Total equity | 4,113,947 | | | 4,394,147 | |
Total liabilities and equity | Total liabilities and equity | $ | 10,469,351 | | | 11,718,504 | | Total liabilities and equity | $ | 10,330,856 | | | 10,620,852 | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars, except per share amounts) | (Thousands of dollars, except per share amounts) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars, except per share amounts) | 2021 | | 2020 | | 2021 | | 2020 |
Revenues and other income | Revenues and other income | | | | | | | | Revenues and other income | | | | | | | |
Revenue from sales to customers | Revenue from sales to customers | $ | 425,324 | | | 750,337 | | 1,311,627 | | | 2,060,127 | | Revenue from sales to customers | $ | 687,549 | | | 425,324 | | $ | 2,038,905 | | | 1,311,627 | |
(Loss) gain on crude contracts | (5,290) | | | 63,247 | | | 319,502 | | | 121,163 | | |
(Loss) gain on derivative instruments | | (Loss) gain on derivative instruments | (59,164) | | | (5,290) | | | (499,794) | | | 319,502 | |
Gain on sale of assets and other income | Gain on sale of assets and other income | 1,831 | | | 3,493 | | | 6,006 | | | 10,283 | | Gain on sale of assets and other income | 2,315 | | | 1,831 | | | 21,217 | | | 6,006 | |
Total revenues and other income | Total revenues and other income | 421,865 | | | 817,077 | | | 1,637,135 | | | 2,191,573 | | Total revenues and other income | 630,700 | | | 421,865 | | | 1,560,328 | | | 1,637,135 | |
Costs and expenses | Costs and expenses | | | | | | | | Costs and expenses | | | | | | | |
Lease operating expenses | Lease operating expenses | 124,491 | | | 147,632 | | | 478,283 | | | 416,460 | | Lease operating expenses | 130,131 | | | 124,491 | | | 403,708 | | | 478,283 | |
Severance and ad valorem taxes | Severance and ad valorem taxes | 6,781 | | | 13,803 | | | 22,645 | | | 36,972 | | Severance and ad valorem taxes | 11,670 | | | 6,781 | | | 32,215 | | | 22,645 | |
Transportation, gathering and processing | Transportation, gathering and processing | 41,322 | | | 54,305 | | | 126,779 | | | 128,748 | | Transportation, gathering and processing | 44,588 | | | 41,322 | | | 137,196 | | | 126,779 | |
Exploration expenses, including undeveloped lease amortization | Exploration expenses, including undeveloped lease amortization | 12,092 | | | 12,358 | | | 61,686 | | | 75,570 | | Exploration expenses, including undeveloped lease amortization | 24,517 | | | 12,092 | | | 49,840 | | | 61,686 | |
Selling and general expenses | Selling and general expenses | 28,509 | | | 55,366 | | | 104,381 | | | 176,258 | | Selling and general expenses | 27,210 | | | 28,509 | | | 85,826 | | | 104,381 | |
Restructuring expenses | Restructuring expenses | 4,982 | | | 0 | | | 46,379 | | | 0 | | Restructuring expenses | — | | | 4,982 | | | — | | | 46,379 | |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | 231,603 | | | 325,562 | | | 769,151 | | | 819,270 | | Depreciation, depletion and amortization | 189,806 | | | 231,603 | | | 615,372 | | | 769,151 | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 10,778 | | | 10,587 | | | 31,213 | | | 29,824 | | Accretion of asset retirement obligations | 12,198 | | | 10,778 | | | 34,854 | | | 31,213 | |
Impairment of assets | Impairment of assets | 219,138 | | | 0 | | | 1,206,284 | | | 0 | | Impairment of assets | — | | | 219,138 | | | 171,296 | | | 1,206,284 | |
Other (benefit) expense | Other (benefit) expense | 20,224 | | | (29,000) | | | (2,957) | | | 26,442 | | Other (benefit) expense | (32,791) | | | 20,224 | | | 58,616 | | | (2,957) | |
Total costs and expenses | Total costs and expenses | 699,920 | | | 590,613 | | | 2,843,844 | | | 1,709,544 | | Total costs and expenses | 407,329 | | | 699,920 | | | 1,588,923 | | | 2,843,844 | |
Operating (loss) income from continuing operations | (278,055) | | | 226,464 | | | (1,206,709) | | | 482,029 | | |
Other (loss) | | | | | | | | |
Interest and other (loss) | (5,177) | | | (4,418) | | | (10,107) | | | (18,134) | | |
Operating income (loss) from continuing operations | | Operating income (loss) from continuing operations | 223,371 | | | (278,055) | | | (28,595) | | | (1,206,709) | |
Other income (loss) | | Other income (loss) | | | | | | | |
Interest income and other (loss) | | Interest income and other (loss) | (1,593) | | | (5,177) | | | (11,459) | | | (10,107) | |
Interest expense, net | Interest expense, net | (45,182) | | | (44,930) | | | (124,877) | | | (145,095) | | Interest expense, net | (46,925) | | | (45,182) | | | (178,399) | | | (124,877) | |
Total other (loss) | (50,359) | | | (49,348) | | | (134,984) | | | (163,229) | | |
(Loss) income from continuing operations before income taxes | (328,414) | | | 177,116 | | | (1,341,693) | | | 318,800 | | |
Income tax (benefit) expense | (62,584) | | | 18,782 | | | (248,890) | | | 38,719 | | |
(Loss) income from continuing operations | (265,830) | | | 158,334 | | | (1,092,803) | | | 280,081 | | |
(Loss) income from discontinued operations, net of income taxes | (778) | | | 953,368 | | | (6,907) | | | 1,027,632 | | |
Net (loss) income including noncontrolling interest | (266,608) | | | 1,111,702 | | | (1,099,710) | | | 1,307,713 | | |
Less: Net (loss) income attributable to noncontrolling interest | (23,055) | | | 22,700 | | | (122,869) | | | 86,257 | | |
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY | $ | (243,553) | | | 1,089,002 | | | (976,841) | | | 1,221,456 | | |
(LOSS) INCOME PER COMMON SHARE – BASIC | | | | | | | | |
Total other loss | | Total other loss | (48,518) | | | (50,359) | | | (189,858) | | | (134,984) | |
Income (loss) from continuing operations before income taxes | | Income (loss) from continuing operations before income taxes | 174,853 | | | (328,414) | | | (218,453) | | | (1,341,693) | |
Income tax expense (benefit) | | Income tax expense (benefit) | 36,838 | | | (62,584) | | | (62,498) | | | (248,890) | |
Income (loss) from continuing operations | | Income (loss) from continuing operations | 138,015 | | | (265,830) | | | (155,955) | | | (1,092,803) | |
(Loss) from discontinued operations, net of income taxes | | (Loss) from discontinued operations, net of income taxes | (706) | | | (778) | | | (600) | | | (6,907) | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | 137,309 | | | (266,608) | | | (156,555) | | | (1,099,710) | |
Less: Net income (loss) attributable to noncontrolling interest | | Less: Net income (loss) attributable to noncontrolling interest | 28,853 | | | (23,055) | | | 85,509 | | | (122,869) | |
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | | NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 108,456 | | | (243,553) | | | $ | (242,064) | | | (976,841) | |
INCOME (LOSS) PER COMMON SHARE – BASIC | | INCOME (LOSS) PER COMMON SHARE – BASIC | | | | | | | |
Continuing operations | Continuing operations | $ | (1.58) | | | 0.85 | | | (6.31) | | | 1.16 | | Continuing operations | $ | 0.70 | | | (1.58) | | | $ | (1.57) | | | (6.31) | |
Discontinued operations | Discontinued operations | (0.01) | | | 5.94 | | | (0.05) | | | 6.14 | | Discontinued operations | — | | | (0.01) | | | — | | | (0.05) | |
Net (loss) income | $ | (1.59) | | | 6.79 | | | (6.36) | | | 7.30 | | |
(LOSS) INCOME PER COMMON SHARE – DILUTED | | | | | | | | |
Net income (loss) | | Net income (loss) | $ | 0.70 | | | (1.59) | | | $ | (1.57) | | | (6.36) | |
INCOME (LOSS) PER COMMON SHARE – DILUTED | | INCOME (LOSS) PER COMMON SHARE – DILUTED | | | | | | | |
Continuing operations | Continuing operations | $ | (1.58) | | | 0.84 | | | (6.31) | | | 1.16 | | Continuing operations | $ | 0.70 | | | (1.58) | | | $ | (1.57) | | | (6.31) | |
Discontinued operations | Discontinued operations | (0.01) | | | 5.92 | | | (0.05) | | | 6.11 | | Discontinued operations | — | | | (0.01) | | | — | | | (0.05) | |
Net (loss) income | $ | (1.59) | | | 6.76 | | | (6.36) | | | 7.27 | | |
Net income (loss) | | Net income (loss) | $ | 0.70 | | | (1.59) | | | $ | (1.57) | | | (6.36) | |
Cash dividends per Common share | Cash dividends per Common share | 0.125 | | | 0.25 | | | 0.50 | | | 0.75 | | Cash dividends per Common share | $ | 0.125 | | | 0.125 | | | 0.375 | | | 0.500 | |
| Average Common shares outstanding (thousands) | Average Common shares outstanding (thousands) | | Average Common shares outstanding (thousands) | |
Basic | Basic | 153,596 | | | 160,366 | | | 153,480 | | | 167,310 | | Basic | 154,439 | | | 153,596 | | | 154,239 | | | 153,480 | |
Diluted | Diluted | 153,596 | | | 160,980 | | | 153,480 | | | 168,105 | | Diluted | 155,932 | | | 153,596 | | | 154,239 | | | 153,480 | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Net (loss) income including noncontrolling interest | $ | (266,608) | | | 1,111,702 | | | (1,099,710) | | | 1,307,713 | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | 137,309 | | | (266,608) | | | $ | (156,555) | | | (1,099,710) | |
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 | 28,323 | | | (17,128) | | | (39,520) | | | 36,927 | | Net (loss) gain from foreign currency translation | (31,308) | | | 28,323 | | | 6,534 | | | (39,520) | |
Retirement and postretirement benefit plans | Retirement and postretirement benefit plans | 3,726 | | | 2,761 | | | (45,219) | | | 8,277 | | Retirement and postretirement benefit plans | 4,653 | | | 3,726 | | | 12,935 | | | (45,219) | |
Deferred loss on interest rate hedges reclassified to interest expense | Deferred loss on interest rate hedges reclassified to interest expense | 297 | | | 585 | | | 905 | | | 1,756 | | Deferred loss on interest rate hedges reclassified to interest expense | — | | | 297 | | | 1,690 | | | 905 | |
| Other comprehensive (loss) income | Other comprehensive (loss) income | 32,346 | | | (13,782) | | | (83,834) | | | 46,960 | | Other comprehensive (loss) income | (26,655) | | | 32,346 | | | 21,159 | | | (83,834) | |
COMPREHENSIVE (LOSS) INCOME | $ | (234,262) | | | 1,097,920 | | | (1,183,544) | | | 1,354,673 | | |
COMPREHENSIVE INCOME (LOSS) | | COMPREHENSIVE INCOME (LOSS) | $ | 110,654 | | | (234,262) | | | $ | (135,396) | | | (1,183,544) | |
See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 |
Operating Activities | Operating Activities | | | | Operating Activities | | | |
Net (loss) income including noncontrolling interest | $ | (1,099,710) | | | 1,307,713 | | |
Adjustments to reconcile net (loss) income to net cash provided by continuing operations activities: | | |
Loss (income) from discontinued operations | 6,907 | | | (1,027,632) | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | (156,555) | | | (1,099,710) | |
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities | | Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities | |
Loss from discontinued operations | | Loss from discontinued operations | 600 | | | 6,907 | |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | 769,151 | | | 819,270 | | Depreciation, depletion and amortization | 615,372 | | | 769,151 | |
Previously suspended exploration costs | 8,255 | | | 12,901 | | |
Dry hole and previously suspended exploration costs | | Dry hole and previously suspended exploration costs | 17,899 | | | 8,255 | |
Amortization of undeveloped leases | Amortization of undeveloped leases | 21,951 | | | 21,680 | | Amortization of undeveloped leases | 13,872 | | | 21,951 | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 31,213 | | | 29,824 | | Accretion of asset retirement obligations | 34,854 | | | 31,213 | |
Impairment of assets | Impairment of assets | 1,206,284 | | | 0 | | Impairment of assets | 171,296 | | | 1,206,284 | |
Noncash restructuring expense | Noncash restructuring expense | 17,565 | | | 0 | | Noncash restructuring expense | — | | | 17,565 | |
Deferred income tax (benefit) expense | Deferred income tax (benefit) expense | (231,748) | | | 50,597 | | Deferred income tax (benefit) expense | (65,149) | | | (231,748) | |
| Mark to market (gain) loss on contingent consideration | (29,476) | | | 512 | | |
Mark to market (gain) loss on crude contracts | (104,463) | | | (100,076) | | |
Mark to market loss (gain) on contingent consideration | | Mark to market loss (gain) on contingent consideration | 105,111 | | | (29,476) | |
Mark to market loss (gain) on derivative instruments | | Mark to market loss (gain) on derivative instruments | 228,497 | | | (104,463) | |
Long-term non-cash compensation | Long-term non-cash compensation | 35,200 | | | 60,567 | | Long-term non-cash compensation | 42,080 | | | 35,200 | |
Net decrease (increase) in noncash operating working capital | (26,261) | | | 40,257 | | |
Net decrease (increase) in noncash working capital | | Net decrease (increase) in noncash working capital | 117,330 | | | (26,261) | |
Other operating activities, net | Other operating activities, net | (26,837) | | | (62,386) | | Other operating activities, net | (33,924) | | | (26,837) | |
Net cash provided by continuing operations activities | Net cash provided by continuing operations activities | 578,031 | | | 1,153,227 | | Net cash provided by continuing operations activities | 1,091,283 | | | 578,031 | |
Investing Activities | Investing Activities | | Investing Activities | |
Property additions and dry hole costs | Property additions and dry hole costs | (648,725) | | | (995,509) | | Property additions and dry hole costs | (564,230) | | | (648,725) | |
Property additions for King's Quay FPS | Property additions for King's Quay FPS | (74,936) | | | (13,637) | | Property additions for King's Quay FPS | (17,734) | | | (74,936) | |
Acquisition of oil and gas properties | 0 | | | (1,212,949) | | |
| Proceeds from sales of property, plant and equipment | Proceeds from sales of property, plant and equipment | 0 | | | 19,072 | | Proceeds from sales of property, plant and equipment | 270,038 | | | — | |
Net cash required by investing activities | Net cash required by investing activities | (723,661) | | | (2,203,023) | | Net cash required by investing activities | (311,926) | | | (723,661) | |
Financing Activities | Financing Activities | | Financing Activities | |
Borrowings on revolving credit facility | Borrowings on revolving credit facility | 450,000 | | | 1,575,000 | | Borrowings on revolving credit facility | 165,000 | | | 450,000 | |
Repayment of revolving credit facility | Repayment of revolving credit facility | (250,000) | | | (1,900,000) | | Repayment of revolving credit facility | (365,000) | | | (250,000) | |
Retirement of debt | | Retirement of debt | (726,358) | | | (12,225) | |
Debt issuance, net of cost | | Debt issuance, net of cost | 541,913 | | | (613) | |
Early redemption of debt cost | | Early redemption of debt cost | (36,756) | | | — | |
Distributions to noncontrolling interest | | Distributions to noncontrolling interest | (100,880) | | | (43,673) | |
Cash dividends paid | Cash dividends paid | (76,790) | | | (125,437) | | Cash dividends paid | (57,896) | | | (76,790) | |
Distributions to noncontrolling interest | (43,673) | | | (97,510) | | |
Early retirement of debt | (12,225) | | | 0 | | |
Withholding tax on stock-based incentive awards | Withholding tax on stock-based incentive awards | (7,094) | | | (6,991) | | Withholding tax on stock-based incentive awards | (4,973) | | | (7,094) | |
Debt issuance, net of cost | (613) | | | 0 | | |
| Capital lease obligation payments | Capital lease obligation payments | (514) | | | (510) | | Capital lease obligation payments | (643) | | | (514) | |
Repurchase of common stock | 0 | | | (405,938) | | |
| Net cash (required) provided by financing activities | Net cash (required) provided by financing activities | 59,091 | | | (961,386) | | Net cash (required) provided by financing activities | (585,593) | | | 59,091 | |
Cash Flows from Discontinued Operations 1 | Cash Flows from Discontinued Operations 1 | | Cash Flows from Discontinued Operations 1 | |
Operating activities | Operating activities | (1,202) | | | 74,361 | | Operating activities | — | | | (1,202) | |
Investing activities | Investing activities | 4,494 | | | 1,985,202 | | Investing activities | — | | | 4,494 | |
Financing activities | Financing activities | 0 | | | (4,914) | | Financing activities | — | | | — | |
Net cash provided by discontinued operations | Net cash provided by discontinued operations | 3,292 | | | 2,054,649 | | Net cash provided by discontinued operations | — | | | 3,292 | |
Cash transferred from discontinued operations to continuing operations | 0 | | | 2,083,565 | | |
| Effect of exchange rate changes on cash and cash equivalents | Effect of exchange rate changes on cash and cash equivalents | (585) | | | 2,593 | | Effect of exchange rate changes on cash and cash equivalents | 697 | | | (585) | |
Net increase (decrease) in cash and cash equivalents | Net increase (decrease) in cash and cash equivalents | (87,124) | | | 74,976 | | Net increase (decrease) in cash and cash equivalents | 194,461 | | | (87,124) | |
Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | 306,760 | | | 359,923 | | Cash and cash equivalents at beginning of period | 310,606 | | | 306,760 | |
Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | $ | 219,636 | | | 434,899 | | Cash and cash equivalents at end of period | $ | 505,067 | | | 219,636 | |
1 Net cash provided by discontinued operations is not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 7.
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
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 September 30, 2020 and 195,083,364 shares at September 30, 2019 | | | | | | | | |
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 September 30, 2021 and 195,100,628 shares at September 30, 2020 | | Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2021 and 195,100,628 shares at September 30, 2020 | | | | | | | |
Balance at beginning of period | Balance at beginning of period | 195,101 | | | 195,083 | | | 195,089 | | | 195,077 | | Balance at beginning of period | 195,101 | | | 195,101 | | | 195,101 | | | 195,089 | |
Exercise of stock options | Exercise of stock options | — | | | — | | | 12 | | | 6 | | Exercise of stock options | — | | | — | | | — | | | 12 | |
Balance at end of period | Balance at end of period | 195,101 | | | 195,083 | | | 195,101 | | | 195,083 | | 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 | 931,429 | | | 933,944 | | | 949,445 | | | 979,642 | | Balance at beginning of period | 915,181 | | | 931,429 | | | 941,692 | | | 949,445 | |
Exercise of stock options, including income tax benefits | Exercise of stock options, including income tax benefits | — | | | — | | | (156) | | | (123) | | Exercise of stock options, including income tax benefits | (35) | | | — | | | (661) | | | (156) | |
Restricted stock transactions and other | Restricted stock transactions and other | (409) | | | — | | | (33,649) | | | (38,732) | | Restricted stock transactions and other | (402) | | | (409) | | | (38,749) | | | (33,649) | |
Share-based compensation | Share-based compensation | 5,298 | | | 7,365 | | | 20,678 | | | 25,041 | | Share-based compensation | 6,483 | | | 5,298 | | | 18,945 | | | 20,678 | |
Adjustments to acquisition valuation | — | | | — | | | — | | | (24,519) | | |
| Balance at end of period | Balance at end of period | 936,318 | | | 941,309 | | | 936,318 | | | 941,309 | | Balance at end of period | 921,227 | | | 936,318 | | | 921,227 | | | 936,318 | |
Retained Earnings | Retained Earnings | | | | | | | | Retained Earnings | | | | | | | |
Balance at beginning of period | Balance at beginning of period | 5,823,426 | | | 5,677,248 | | | 6,614,304 | | | 5,513,529 | | Balance at beginning of period | 4,980,428 | | | 5,823,426 | | | 5,369,538 | | | 6,614,304 | |
Net (loss) income for the period | (243,553) | | | 1,089,002 | | | (976,841) | | | 1,221,456 | | |
Net (loss) attributable to Murphy | | Net (loss) attributable to Murphy | 108,456 | | | (243,553) | | | (242,064) | | | (976,841) | |
| Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact | — | | | — | | | — | | | 116,768 | | |
| Cash dividends | Cash dividends | (19,200) | | | (39,934) | | | (76,790) | | | (125,437) | | Cash dividends | (19,306) | | | (19,200) | | | (57,896) | | | (76,790) | |
Balance at end of period | Balance at end of period | 5,560,673 | | | 6,726,316 | | | 5,560,673 | | | 6,726,316 | | Balance at end of period | 5,069,578 | | | 5,560,673 | | | 5,069,578 | | | 5,560,673 | |
Accumulated Other Comprehensive Loss | Accumulated Other Comprehensive Loss | | | | | | | | Accumulated Other Comprehensive Loss | | | | | | | |
Balance at beginning of period | Balance at beginning of period | (690,341) | | | (549,045) | | | (574,161) | | | (609,787) | | Balance at beginning of period | (553,519) | | | (690,341) | | | (601,333) | | | (574,161) | |
Foreign currency translation (loss) gain, net of income taxes | 28,323 | | | (17,128) | | | (39,520) | | | 36,927 | | |
Foreign currency translation gain (loss), net of income taxes | | Foreign currency translation gain (loss), net of income taxes | (31,308) | | | 28,323 | | | 6,534 | | | (39,520) | |
Retirement and postretirement benefit plans, net of income taxes | Retirement and postretirement benefit plans, net of income taxes | 3,726 | | | 2,761 | | | (45,219) | | | 8,277 | | Retirement and postretirement benefit plans, net of income taxes | 4,653 | | | 3,726 | | | 12,935 | | | (45,219) | |
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 | 297 | | | 585 | | | 905 | | | 1,756 | | Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | — | | | 297 | | | 1,690 | | | 905 | |
| Balance at end of period | Balance at end of period | (657,995) | | | (562,827) | | | (657,995) | | | (562,827) | | Balance at end of period | (580,174) | | | (657,995) | | | (580,174) | | | (657,995) | |
Treasury Stock | Treasury Stock | | | | | | | | Treasury Stock | | | | | | | |
Balance at beginning of period | Balance at beginning of period | (1,691,070) | | | (1,517,217) | | | (1,717,217) | | | (1,249,162) | | Balance at beginning of period | (1,656,591) | | | (1,691,070) | | | (1,690,661) | | | (1,717,217) | |
Purchase of treasury shares | — | | | (106,014) | | | — | | | (405,938) | | |
| Awarded restricted stock, net of forfeitures | Awarded restricted stock, net of forfeitures | 409 | | | — | | | 26,556 | | | 31,869 | | Awarded restricted stock, net of forfeitures | 343 | | | 409 | | | 33,888 | | | 26,556 | |
Balance at end of period – 41,502,003 shares of Common Stock in 2020 and 37,853,330 shares of Common Stock in 2019, at cost | (1,690,661) | | | (1,623,231) | | | (1,690,661) | | | (1,623,231) | | |
Exercise of stock options | | Exercise of stock options | 24 | | | — | | | 549 | | | — | |
Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost | | Balance at end of period – 40,656,661 shares of Common Stock in 2021 and 41,502,003 shares of Common Stock in 2020, at cost | (1,656,224) | | | (1,690,661) | | | (1,656,224) | | | (1,690,661) | |
Murphy Shareholders’ Equity | Murphy Shareholders’ Equity | 4,343,436 | | | 5,676,650 | | | 4,343,436 | | | 5,676,650 | | Murphy Shareholders’ Equity | 3,949,508 | | | 4,343,436 | | | 3,949,508 | | | 4,343,436 | |
Noncontrolling Interest | Noncontrolling Interest | | | | | | | | Noncontrolling Interest | |
Balance at beginning of period | Balance at beginning of period | 204,937 | | | 358,532 | | | 337,151 | | | 368,343 | | Balance at beginning of period | 161,228 | | | 204,937 | | | 179,810 | | | 337,151 | |
Acquisition closing adjustments | — | | | (3,328) | | | — | | | (7,920) | | |
Net (loss) income attributable to noncontrolling interest | (23,055) | | | 22,700 | | | (122,869) | | | 86,257 | | |
| Net income (loss) attributable to noncontrolling interest | | Net income (loss) attributable to noncontrolling interest | 28,853 | | | (23,055) | | | 85,509 | | | (122,869) | |
Distributions to noncontrolling interest owners | Distributions to noncontrolling interest owners | (11,273) | | | (28,734) | | | (43,673) | | | (97,510) | | Distributions to noncontrolling interest owners | (25,642) | | | (11,273) | | | (100,880) | | | (43,673) | |
Balance at end of period | Balance at end of period | 170,609 | | | 349,170 | | | 170,609 | | | 349,170 | | Balance at end of period | 164,439 | | | 170,609 | | | 164,439 | | | 170,609 | |
Total Equity | Total Equity | $ | 4,514,045 | | | 6,025,820 | | | 4,514,045 | | | 6,025,820 | | Total Equity | $ | 4,113,947 | | | 4,514,045 | | | $ | 4,113,947 | | | 4,514,045 | |
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) 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, further discussed in Note P – Acquisitions, 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 September 30, 2020,2021, our maximum exposure to loss was $3.5$3.4 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 20202021 and December 31, 2019,2020, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 20202021 and 2019,2020, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
FinancialConsolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 20192020 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 20202021 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Financial Instruments– Credit Losses. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
Income Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. Early adoption is permitted. The Company is currently assessingadopted this guidance in the potentialfirst quarter of 2021 and it did not have a material impact of this ASU toon its consolidated financial statements.
Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018,Recent Accounting Pronouncements
None affecting the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years ending after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.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 are primarilyinclude long-term floating commodity index priced except for certainand natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.
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 nine-month periods ended September 30, 2020,2021, the Company recognized $425.3$687.5 million and $1,311.6$2,038.9 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and nine-month periods ended September 30, 2019,2020, the Company recognized $750.3$425.3 million and $2,060.1$1,311.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
Net crude oil and condensate revenue | Net crude oil and condensate revenue | | | | | | | | Net crude oil and condensate revenue | | | | | | | |
United States | United States | Onshore | $ | 86,498 | | | 219,515 | | | 272,284 | | | 547,756 | | United States | Onshore | $ | 167,010 | | | 86,498 | | | 464,767 | | | 272,284 | |
| | Offshore | 216,918 | | | 398,518 | | | 714,143 | | | 1,090,462 | | | Offshore | 340,001 | | | 216,918 | | | 1,079,418 | | | 714,143 | |
Canada | Canada | Onshore | 32,358 | | | 31,758 | | | 67,268 | | | 88,730 | | Canada | Onshore | 29,110 | | | 32,358 | | | 89,708 | | | 67,268 | |
| | Offshore | 19,173 | | | 28,407 | | | 54,864 | | | 115,686 | | | Offshore | 20,499 | | | 19,173 | | | 70,333 | | | 54,864 | |
Other | Other | | 0 | | | 1,933 | | | 1,806 | | | 7,908 | | Other | | — | | | — | | | — | | | 1,806 | |
Total crude oil and condensate revenue | Total crude oil and condensate revenue | 354,947 | | | 680,131 | | | 1,110,365 | | | 1,850,542 | | Total crude oil and condensate revenue | 556,620 | | | 354,947 | | | 1,704,226 | | | 1,110,365 | |
| Net natural gas liquids revenue | Net natural gas liquids revenue | | Net natural gas liquids revenue | |
United States | United States | Onshore | 6,766 | | | 5,557 | | | 16,145 | | | 22,497 | | United States | Onshore | 16,356 | | | 6,766 | | | 33,480 | | | 16,145 | |
| | Offshore | 4,765 | | | 8,414 | | | 13,255 | | | 18,184 | | | Offshore | 11,046 | | | 4,765 | | | 31,866 | | | 13,255 | |
Canada | Canada | Onshore | 2,780 | | | 2,751 | | | 6,090 | | | 8,987 | | Canada | Onshore | 4,501 | | | 2,780 | | | 11,728 | | | 6,090 | |
Total natural gas liquids revenue | Total natural gas liquids revenue | 14,311 | | | 16,722 | | | 35,490 | | | 49,668 | | Total natural gas liquids revenue | 31,903 | | | 14,311 | | | 77,074 | | | 35,490 | |
| Net natural gas revenue | Net natural gas revenue | | Net natural gas revenue | |
United States | United States | Onshore | 4,529 | | | 5,848 | | | 14,177 | | | 20,762 | | United States | Onshore | 11,127 | | | 4,529 | | | 24,442 | | | 14,177 | |
| | Offshore | 9,827 | | | 15,879 | | | 35,487 | | | 29,575 | | | Offshore | 17,444 | | | 9,827 | | | 56,855 | | | 35,487 | |
Canada | Canada | Onshore | 41,710 | | | 31,757 | | | 116,108 | | | 109,580 | | Canada | Onshore | 70,455 | | | 41,710 | | | 176,308 | | | 116,108 | |
Total natural gas revenue | Total natural gas revenue | 56,066 | | | 53,484 | | | 165,772 | | | 159,917 | | Total natural gas revenue | 99,026 | | | 56,066 | | | 257,605 | | | 165,772 | |
Total revenue from contracts with customers | Total revenue from contracts with customers | 425,324 | | | 750,337 | | | 1,311,627 | | | 2,060,127 | | Total revenue from contracts with customers | 687,549 | | | 425,324 | | | 2,038,905 | | | 1,311,627 | |
| (Loss) gain on crude contracts | (5,290) | | | 63,247 | | | 319,502 | | | 121,163 | | |
(Loss) gain on derivative instruments | | (Loss) gain on derivative instruments | (59,164) | | | (5,290) | | | (499,794) | | | 319,502 | |
Gain on sale of assets and other income | Gain on sale of assets and other income | 1,831 | | | 3,493 | | | 6,006 | | | 10,283 | | Gain on sale of assets and other income | 2,315 | | | 1,831 | | | 21,217 | | | 6,006 | |
Total revenue and other income | Total revenue and other income | $ | 421,865 | | | 817,077 | | | 1,637,135 | | | 2,191,573 | | Total revenue and other income | $ | 630,700 | | | 421,865 | | | 1,560,328 | | | 1,637,135 | |
Contract Balances and Asset Recognition
As of September 30, 2020,2021, and December 31, 2019,2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $70.8$144.0 million and $186.8$135.2 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, (see Note B), the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any upstream oil and gas salerevenue contracts that have financing components as ofat September 30, 2020.2021.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
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 September 30, 2020,2021, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Long-Term Contracts Outstanding at September 30, 2020 |
| | | | | | | | Approximate Volumes2021 |
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 | | Q1 2023 | | Deliveries from dedicated acreage in Eagle Ford | | As produced |
Canada | | Natural Gas | | Q4 2020 | | Contracts to sell natural gas at Alberta AECO fixed prices | | 59 MMCFD |
Canada | | Natural Gas | | Q4 2020 | | Contracts to sell natural gas at USD Index pricing | | 60 MMCFD |
Canada | | Natural Gas | | Q4 2021 | | Contracts to sell natural gas at USD Indexindex pricing | | 10 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at Malin USD index pricing | | 8 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at CAD fixed prices | | 205 MMCFD |
Canada | | Natural Gas | | Q4 2022 | | Contracts to sell natural gas at USD Indexfixed pricing | | 3520 MMCFD |
Canada | | Natural Gas | | Q4 2023 | 1 | Contracts to sell natural gas at USD index pricing | | 25 MMCFD |
Canada | | Natural Gas | | Q4 2023 | | Contracts to sell natural gas at CAD fixed prices | | 38 MMCFD |
Canada | | Natural Gas | | Q4 2024 | | Contracts to sell natural gas at USD Indexindex pricing | | 3031 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 Indexindex pricing | | 49 MMCFD |
| | | | | | | | |
1 These contracts are scheduled to commence after the balance sheet date, at various dates between Q4 2021 and Q1 2022.Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant, and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
AtAs of September 30, 2020,2021, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $187.9$186.6 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 20202021 and 2019.
| | | | | | | | | | | |
(Thousands of dollars) | 2020 | | 2019 |
Beginning balance at January 1 | $ | 217,326 | | | 207,855 | |
Additions pending the determination of proved reserves | 9,941 | | | 86,025 | |
| | | |
Capitalized exploratory well costs charged to expense | (39,408) | | | (13,145) | |
Balance at September 30 | $ | 187,859 | | | 280,735 | |
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below). The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017.2020.
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 | 5,007 | | | 9,941 | |
| | | |
Capitalized exploratory well costs charged to expense | — | | | (39,408) | |
Balance at September 30 | $ | 186,623 | | | 187,859 | |
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below).
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
| | | September 30, | | September 30, |
| | 2020 | | 2019 | | 2021 | | 2020 |
| (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 | $ | 8,000 | | | 1 | | | 0 | | | 64,711 | | | 5 | | | 5 | | Zero to one year | $ | 3,297 | | | 2 | | | 2 | | | 8,000 | | | 1 | | | — | |
One to two years | One to two years | 54,334 | | | 5 | | | 5 | | | 63,615 | | | 1 | | | 1 | | One to two years | — | | | — | | | — | | | 54,334 | | | 5 | | | 5 | |
Two to three years | Two to three years | 0 | | | 0 | | | 0 | | | 27,500 | | | 1 | | | 0 | | Two to three years | 53,078 | | | 5 | | | 5 | | | — | | | — | | | — | |
Three years or more | Three years or more | 125,525 | | | 6 | | | 0 | | | 124,909 | | | 5 | | | 0 | | Three years or more | 130,248 | | | 6 | | | — | | | 125,525 | | | 6 | | | — | |
| | $ | 187,859 | | | 12 | | | 5 | | | 280,735 | | | 12 | | | 6 | | | $ | 186,623 | | | 13 | | | 7 | | | 187,859 | | | 12 | | | 5 | |
Of the $179.9$183.3 million of exploratory well costs capitalized more than one year at September 30, 2020, $88.22021, $92.3 million is in Vietnam, $46.0$45.0 million is in the U.S., $25.3$25.9 million is in Brunei, $15.6$15.3 million is in Mexico, and $4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Impairments
During the first quarter of 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans.
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response tofrom the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 38)pandemic) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $1,206.3 million to reduce the carrying values to their estimated fair values at select properties.
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The following table reflects the recognized impairments for the nine months ended September 30, 2021 and 2020.
| | | | | |
| Nine Months Ended |
(Thousands of dollars) | September 30, 2020 |
U.S. | $ | 1,152,515 | |
| |
Other Foreign | 39,709 | |
Corporate | 14,060 | |
| $ | 1,206,284 | |
| | | | | | | | | | | |
| Nine Months Ended September 30, |
(Thousands of dollars) | 2021 | | 2020 |
U.S. | $ | — | | | 1,152,515 | |
Canada | 171,296 | | | — | |
Other Foreign | — | | | 39,709 | |
Corporate | — | | | 14,060 | |
| $ | 171,296 | | | 1,206,284 | |
Divestments
In July 2019,During the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimburses the Company completed a divestiture of its 2 subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $960.0 million was recorded as part of discontinued operations on the Consolidated Statement of Operations during 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy was entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020, however the results were not achieved by PTTEP.
for previously incurred capital expenditures.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note E – Discontinued Operations and 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 and its former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 20202021 and 20192020 were as follows:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Revenues | Revenues | $ | 0 | | | 972,737 | | | 4,074 | | | 1,328,110 | | Revenues | $ | 144 | | | — | | | $ | 801 | | | 4,074 | |
Costs and expenses | Costs and expenses | | Costs and expenses | |
Lease operating expenses | 0 | | | 6,262 | | | 0 | | | 127,138 | | |
Depreciation, depletion and amortization | 0 | | | (1) | | | 0 | | | 33,697 | | |
Other costs and expenses | 778 | | | 11,079 | | | 10,981 | | | 81,560 | | |
| Other costs and expenses (benefits) | | Other costs and expenses (benefits) | 850 | | | 778 | | | 1,401 | | | 10,981 | |
(Loss) income before taxes | (Loss) income before taxes | (778) | | | 955,397 | | | (6,907) | | | 1,085,715 | | (Loss) income before taxes | (706) | | | (778) | | | (600) | | | (6,907) | |
Income tax expense | Income tax expense | 0 | | | 2,029 | | | 0 | | | 58,083 | | Income tax expense | — | | | — | | | — | | | — | |
(Loss) income from discontinued operations | (Loss) income from discontinued operations | $ | (778) | | | 953,368 | | | (6,907) | | | 1,027,632 | | (Loss) income from discontinued operations | $ | (706) | | | (778) | | | $ | (600) | | | (6,907) | |
The following table presentsAs of September 30, 2021, assets held for sale on the Consolidated Balance Sheet include the carrying value of the major categoriesnet property, plant equipment of assets and liabilities of theCA-2 project in Brunei exploration and production operations, the U.K. refining and marketing operations and the Company’s office building in El Dorado, Arkansas and 2 airplanes that are reflected asArkansas. 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 onincluded the King’s Quay Floating Production System (FPS) of $250.1 million (sold in March 2021), the Brunei exploration and production properties, and the Company’s Consolidated Balance Sheets. Subsequent to period end, 1 of the planes has been sold.office building in El Dorado, Arkansas.
| (Thousands of dollars) | (Thousands of dollars) | September 30, 2020 | | December 31, 2019 | (Thousands of dollars) | September 30, 2021 | | December 31, 2020 |
Current assets | Current assets | | | | Current assets | | | |
Cash | Cash | $ | 29,420 | | | 25,185 | | Cash | $ | — | | | 10,185 | |
Accounts receivable | 425 | | | 4,834 | | |
| Inventories | Inventories | 406 | | | 406 | | Inventories | — | | | 406 | |
Prepaid expenses and other | 831 | | | 1,882 | | |
| Property, plant, and equipment, net | Property, plant, and equipment, net | 68,393 | | | 82,116 | | Property, plant, and equipment, net | 40,987 | | | 307,704 | |
Deferred income taxes and other assets | Deferred income taxes and other assets | 9,441 | | | 9,441 | | Deferred income taxes and other assets | — | | | 9,441 | |
| Total current assets associated with assets held for sale | Total current assets associated with assets held for sale | $ | 108,916 | | | 123,864 | | Total current assets associated with assets held for sale | $ | 40,987 | | | 327,736 | |
| Current liabilities | Current liabilities | | | | Current liabilities | | | |
Accounts payable | Accounts payable | $ | 5,481 | | | 3,702 | | Accounts payable | $ | — | | | 5,306 | |
| Other accrued liabilities | | Other accrued liabilities | — | | | 45 | |
Current maturities of long-term debt (finance lease) | Current maturities of long-term debt (finance lease) | 728 | | | 705 | | Current maturities of long-term debt (finance lease) | — | | | 737 | |
Taxes payable | Taxes payable | 1,510 | | | 1,411 | | Taxes payable | — | | | 1,510 | |
| Long-term debt (finance lease) | Long-term debt (finance lease) | 6,702 | | | 7,240 | | Long-term debt (finance lease) | — | | | 6,513 | |
Asset retirement obligation | Asset retirement obligation | 256 | | | 240 | | Asset retirement obligation | — | | | 261 | |
Total current liabilities associated with assets held for sale | Total current liabilities associated with assets held for sale | $ | 14,677 | | | 13,298 | | Total current liabilities associated with assets held for sale | $ | — | | | 14,372 | |
|
Note F – Financing Arrangements and Debt
As of September 30, 2020,2021, the Company had a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At September 30, 2020,2021, the Company had $200.0 millionno outstanding borrowings under the RCF and $3.7$31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2020,2021, the interest rate in effect on borrowings under the facility was 1.84%1.78%. At September 30, 2020,2021, the Company was in compliance with all covenants related to the RCF.
In March 2021, the Company issued $550.0 million of new notes that bear interest at a rate of 6.375% and mature on July 15, 2028. The Company incurred transaction costs of $8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year, beginning July 15, 2021. The proceeds of the $550.0 million notes, along with cash on hand, were used to redeem and cancel $259.3 million of the Company’s 4.00% notes due June 2022 and $317.1 million of the Company’s 4.95% notes due December 2022 (originally issued as 3.70% notes due 2022; collectively
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)
the 2022 Notes). The cost of the debt extinguishment of $36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
In August 2021, the Company redeemed $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the nine months ended September 30, 2021. The cash costs of $2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 15, 2024.
Subsequent to quarter end, the Company issued a notice of partial redemption with respect to $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 (2024 Notes). The Company will redeem the 2024 Notes at the applicable redemption price set forth in the indenture governing the 2024 Notes, plus accrued and unpaid interest, if any, to the date of redemption. The redemption date of the 2024 Notes will be December 2, 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 |
Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | | | | Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | | | |
(Increase) decrease in accounts receivable ¹ | $ | 251,706 | | | (128,698) | | |
Decrease in accounts receivable ¹ | | Decrease in accounts receivable ¹ | $ | 75,100 | | | 251,706 | |
Decrease in inventories | Decrease in inventories | 4,747 | | | 4,398 | | Decrease in inventories | 9,718 | | | 4,747 | |
(Increase) in prepaid expenses | (Increase) in prepaid expenses | (17,400) | | | (3,745) | | (Increase) in prepaid expenses | (6,682) | | | (17,400) | |
Increase (decrease) in accounts payable and accrued liabilities ¹ | Increase (decrease) in accounts payable and accrued liabilities ¹ | (264,078) | | | 165,224 | | Increase (decrease) in accounts payable and accrued liabilities ¹ | 40,687 | | | (264,078) | |
Increase (decrease) in income taxes payable | (1,236) | | | 3,078 | | |
(Decrease) in income taxes payable | | (Decrease) in income taxes payable | (1,493) | | | (1,236) | |
Net (increase) decrease in noncash operating working capital | Net (increase) decrease in noncash operating working capital | $ | (26,261) | | | 40,257 | | Net (increase) decrease in noncash operating working capital | $ | 117,330 | | | (26,261) | |
Supplementary disclosures: | Supplementary disclosures: | | | | Supplementary disclosures: | | | |
Cash income taxes paid, net of refunds | Cash income taxes paid, net of refunds | $ | (12,559) | | | (4,563) | | Cash income taxes paid, net of refunds | $ | 1,685 | | | (12,559) | |
Interest paid, net of amounts capitalized of $5.9 million in 2020 and $0.2 million in 2019 | 139,651 | | | 137,116 | | |
Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020 | | Interest paid, net of amounts capitalized of $11.6 million in 2021 and $5.9 million in 2020 | 127,793 | | | 139,651 | |
| Non-cash investing activities: | Non-cash investing activities: | | Non-cash investing activities: | |
Asset retirement costs capitalized ² | Asset retirement costs capitalized ² | $ | 6,342 | | | 48,203 | | Asset retirement costs capitalized ² | $ | 36,300 | | | 6,342 | |
(Increase) decrease in capital expenditure accrual | 74,742 | | | (52,659) | | |
Decrease in capital expenditure accrual | | Decrease in capital expenditure accrual | 31,301 | | | 74,742 | |
1 Excludes receivable/payable balances relating to mark-to-market of crude contractsderivative instruments and contingent consideration relating to acquisitions.
2 2019 includesExcludes non-cash capitalized cost offset by impairment of $74.4 million in the first quarter of 2021 and a gain in other operating income of $71.8 million following a commercial agreement to sanction an asset retirement obligations assumed as partlife extension project at Terra Nova in the third quarter of 2021, which extended the LLOG acquisitionlife of Terra Nova by approximately 10 years.
$37.3 million. See Note P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $63.0 million due to a lower discount rate and lower plan assets compared to December 31, 2019.
The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 20202021 and 2019.2020.
| | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Service cost | Service cost | $ | 1,664 | | | 2,064 | | | 342 | | | 421 | | Service cost | $ | 1,770 | | | 1,664 | | | 328 | | | 342 | |
Interest cost | Interest cost | 4,827 | | | 7,151 | | | 612 | | | 945 | | Interest cost | 4,258 | | | 4,827 | | | 521 | | | 612 | |
Expected return on plan assets | Expected return on plan assets | (5,773) | | | (6,455) | | | 0 | | | 0 | | Expected return on plan assets | (6,038) | | | (5,773) | | | — | | | — | |
Amortization of prior service cost (credit) | Amortization of prior service cost (credit) | 149 | | | 248 | | | 0 | | | (98) | | Amortization of prior service cost (credit) | 155 | | | 149 | | | — | | | — | |
Recognized actuarial loss | Recognized actuarial loss | 5,690 | | | 3,516 | | | (24) | | | 0 | | Recognized actuarial loss | 5,269 | | | 5,690 | | | (8) | | | (24) | |
Net periodic benefit expense | Net periodic benefit expense | $ | 6,557 | | | 6,524 | | | 930 | | | 1,268 | | Net periodic benefit expense | $ | 5,414 | | | 6,557 | | | 841 | | | 930 | |
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Service cost | Service cost | $ | 5,996 | | | 6,188 | | | 1,235 | | | 1,261 | | Service cost | $ | 5,306 | | | 5,996 | | | 981 | | | 1,235 | |
Interest cost | Interest cost | 16,381 | | | 21,402 | | | 2,200 | | | 2,833 | | Interest cost | 12,844 | | | 16,381 | | | 1,563 | | | 2,200 | |
Expected return on plan assets | Expected return on plan assets | (18,414) | | | (19,285) | | | 0 | | | 0 | | Expected return on plan assets | (18,326) | | | (18,414) | | | — | | | — | |
Amortization of prior service cost (credit) | Amortization of prior service cost (credit) | 515 | | | 741 | | | 0 | | | (293) | | Amortization of prior service cost (credit) | 467 | | | 515 | | | — | | | — | |
Recognized actuarial loss | Recognized actuarial loss | 14,223 | | | 10,538 | | | (24) | | | 0 | | Recognized actuarial loss | 15,829 | | | 14,223 | | | (23) | | | (24) | |
Net periodic benefit expense | Net periodic benefit expense | 18,701 | | | 19,584 | | | 3,411 | | | 3,801 | | Net periodic benefit expense | $ | 16,120 | | | 18,701 | | | 2,521 | | | 3,411 | |
Other - curtailment | Other - curtailment | 586 | | | 0 | | | (1,825) | | | 0 | | Other - curtailment | — | | | 586 | | | — | | | (1,825) | |
Other - special termination benefits | Other - special termination benefits | 8,435 | | | 0 | | | 0 | | | 0 | | Other - special termination benefits | — | | | 8,435 | | | — | | | — | |
Total net periodic benefit expense | Total net periodic benefit expense | $ | 27,722 | | | 19,584 | | | 1,586 | | | 3,801 | | Total net periodic benefit expense | $ | 16,120 | | | 27,722 | | | 2,521 | | | 1,586 | |
The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations. The curtailment and special termination benefits components are included in the line item “Restructuring expenses” in Consolidated Statement of Operations.
During the nine-month period ended September 30, 2020,2021, the Company made contributions of $27.4$31.0 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 20202021 for the Company’s defined benefit pension and postretirement plans is anticipated to be $10.3$10.9 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The 2017 Annual Incentive Plan (2017 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with theThe 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.
The 2020 Long-Term Plan and the 2018 Long-Term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5,000,0005000000 shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.
During the first nine months of 2021, the Committee granted the following awards from the 2020 Long-Term Plan:
2020 Long-Term Incentive Plan
| | | | | | | | | | | | | | | | | | | | | | | |
Type of Award | Number of Awards Granted | | Grant Date | | Grant Date Fair Value | | Valuation Methodology |
Performance Based RSUs 1 | 1,156,800 | | | February 2, 2021 | | $ | 16.03 | | | Monte Carlo at Grant Date |
Time Based RSUs 2 | 385,600 | | | February 2, 2021 | | $ | 12.30 | | | Average Stock Price at Grant Date |
Cash Settled RSUs 3 | 1,022,700 | | | February 2, 2021 | | $ | 12.30 | | | Average Stock Price at Grant Date |
1 Performance based RSUs are scheduled to vest over a three year performance period.
2 Time based RSUs are generally scheduled to vest over three years from the date of grant.
3 Cash settled RSUs are scheduled to vest over three years from the date of grant.
The Company also has a Stock Plan for Non-Employee Directors (2018 NED Plan)that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan. All awards on or after May 12, 2021, will be made under the 2021 NED Plan.
During the first nine months of 2020,2021, the Committee granted 999,700 performance-based RSUs and 340,600the following awards to Non-Employee Directors:
2018 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 | 182,652 | | | February 3, 2021 | | $ | 13.14 | | | Closing Stock Price at Grant Date |
1 Non-employee directors time-based RSUs to certain employees under the 2018 Long-Term Plan. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $21.51 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $21.68 per unit. Additionally, in February 2020, the Committee granted 1,152,500 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2020 was $21.68. Also, in February, the Committee granted 106,248 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 NED Plan. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $22.59 per unit on date of grant.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.
All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2020.2021.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of dollars) | (Thousands of dollars) | 2020 | | 2019 | (Thousands of dollars) | 2021 | | 2020 |
Compensation charged against income before tax benefit | Compensation charged against income before tax benefit | $ | 17,542 | | | 39,884 | | Compensation charged against income before tax benefit | $ | 29,145 | | | 17,542 | |
Related income tax benefit recognized in income | Related income tax benefit recognized in income | 2,278 | | | 6,204 | | Related income tax benefit recognized in income | 4,120 | | | 2,278 | |
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note J – Earnings perPer Share
Net (loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 20202021 and 2019.2020. The following table reports the weighted-average shares outstanding used for these computations.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Weighted-average shares) | (Weighted-average shares) | 2020 | | 2019 | | 2020 | | 2019 | (Weighted-average shares) | 2021 | | 2020 | | 2021 | | 2020 |
Basic method | Basic method | 153,596,109 | | | 160,365,705 | | | 153,479,654 | | | 167,310,202 | | Basic method | 154,439,313 | | | 153,596,109 | | | 154,239,440 | | | 153,479,654 | |
Dilutive stock options and restricted stock units ¹ | Dilutive stock options and restricted stock units ¹ | 0 | | | 614,333 | | | 0 | | | 795,025 | | Dilutive stock options and restricted stock units ¹ | 1,492,949 | | | — | | | — | | | — | |
Diluted method | Diluted method | 153,596,109 | | | 160,980,038 | | | 153,479,654 | | | 168,105,227 | | Diluted method | 155,932,262 | | | 153,596,109 | | | 154,239,440 | | | 153,479,654 | |
1 Due to a net loss recognized by the Company for the nine-month period ended September 30, 2021 and the three-month and nine-month periods ended September 30, 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 |
Antidilutive stock options excluded from diluted shares | Antidilutive stock options excluded from diluted shares | 2,111,068 | | | 2,903,768 | | | 2,305,973 | | | 3,016,361 | | Antidilutive stock options excluded from diluted shares | 1,316,222 | | | 2,111,068 | | | 1,502,758 | | | 2,305,973 | |
Weighted average price of these options | Weighted average price of these options | $ | 38.54 | | | $ | 44.65 | | | $ | 40.15 | | | $ | 45.38 | | Weighted average price of these options | $ | 34.42 | | | $ | 38.54 | | | $ | 34.97 | | | $ | 40.15 | |
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, the Company’s effective income tax rates were as follows:
| | | 2020 | | 2019 | | 2021 | | 2020 |
Three months ended September 30, | Three months ended September 30, | 19.1% | | 10.6% | Three months ended September 30, | 21.1% | | 19.1% |
Nine months ended September 30, | Nine months ended September 30, | 18.6% | | 12.1% | Nine months ended September 30, | 28.6% | | 18.6% |
The effective tax rate for the three-month period ended September 30, 2021 was above the U.S. statutory tax rate of 21% primarily due to income generated in Canada, which has a higher tax rate, offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, which has the impact of decreasing the effective tax rate on income.
The effective tax rate for the three-month period ended September 30, 2020 was below the U.S. statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM.
The effective tax rate for the three-monthnine-month period ended September 30, 20192021 was belowabove 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 income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million.overall loss.
The effective tax rate for the nine-month period ended September 30, 2020 was below the U.S. statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.
The effective tax rate for the nine-month period ended September 30, 2019 was below the statutory tax rate of 21% due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15 million, a reduction of the Alberta provincial corporate income tax rate that reduced the future deferred tax liability by $13 million, and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.authorities, and currently the Company is under audit in several of these jurisdictions. These audits often take multiple years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of September 30, 2020,2021, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; Malaysia – 2013;2014; and United Kingdom – 2018. Following the divestment of Malaysia in the
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K– Income Taxes (Contd.)
United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of 2019, the Company has retained certain possible tax and other liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments, 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 untiland amortized to the anticipated transactions occur.income statement over time. During the nine-month period ended September 30, 2021, the Company redeemed all of the remaining notes due 2022 and expensed the remainder of the previously deferred loss on the interest rate swap of $2.1 million to Interest expense in the Consolidated Statement of Operations.
Commodity Price Risks
At September 30, 2020, theThe Company had 45,000 barrels per day in WTIhas entered into crude oil swap financial contracts maturing through December 2020 at an average price of $56.42,swaps and 18,000 barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2021 at an average price of $43.31.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 September 30, 2019, the Company had 35,000 barrels2021, volumes per day in WTIassociated with outstanding crude oil swap financialderivative contracts maturing through December 2019 at anand the weighted average price of $60.51 and 35,000 barrels per day in WTI crude oil swap financialprices for these contracts maturing through December 2020 at an average price of $57.59.are as follows:
| | | | | | | | | | | | | | |
| | September 30, 2021 |
| | 2021 | | 2022 |
NYMEX WTI swap contracts: | | | | |
Volume per day (Bbl): | | 45,000 | | | 20,000 | |
Price per Bbl: | | $ | 42.77 | | | $ | 44.88 | |
| | | | |
NYMEX WTI collar contracts: | | | | |
Volume per day (Bbl): | | — | | | 16,000 | |
Price per Bbl: | | | | |
Ceiling: | | $ | — | | | $ | 71.83 | |
Floor: | | — | | | 60.38 | |
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had 0no foreign currency exchange short-term derivatives outstanding at September 30, 20202021 and 2019.2020.
At September 30, 20202021 and December 31, 2019,2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2020 | | December 31, 2019 |
(Thousands of dollars) | | Asset (Liability) Derivatives | | Asset (Liability) Derivatives |
Type of Derivative Contract | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
Commodity | | Accounts receivable | | $ | 93,774 | | | Accounts payable | | $ | (33,364) | |
For the three-month and nine-month periods ended September 30, 2020 and 2019, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Gain (Loss) | | Gain (Loss) |
(Thousands of dollars) | | Statement of Operations Location | | Three Months Ended September 30, | | Nine months ended September 30, |
Type of Derivative Contract | | | 2020 | | 2019 | | 2020 | | 2019 |
Commodity | | (Loss) gain on crude contracts | | $ | (5,290) | | | 63,247 | | | $ | 319,502 | | | 121,163 | |
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During the nine-month periods ended September 30, 2020 and 2019, $1.1 million and $2.2 million, respectively, of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at September 30, 2020 was $2.0 million and is recorded, net of income taxes of $0.5 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.4 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
(Thousands of dollars) | | Asset (Liability) Derivatives | | Asset (Liability) Derivatives |
Type of Derivative Contract | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
Commodity swaps | | Accounts receivable | | $ | — | | | Accounts receivable | | 13,050 | |
| | Accounts payable | | (312,448) | | | Accounts payable | | (89,842) | |
| | Deferred credits and other liabilities | | (41,645) | | | Deferred credits and other liabilities | | (12,833) | |
Commodity collars | | Accounts receivable | | — | | | Accounts receivable | | — | |
| | Accounts payable | | (15,929) | | | Accounts payable | | — | |
For the three-month and nine-month periods ended September 30, 2021 and 2020, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Gain (Loss) | | Gain (Loss) |
(Thousands of dollars) | | Statement of Operations Location | | Three Months Ended September 30, | | Nine months ended September 30, |
Type of Derivative Contract | | | 2021 | | 2020 | | 2021 | | 2020 |
Commodity swaps | | (Loss) gain on derivative instruments | | $ | (43,235) | | | (5,290) | | | (483,865) | | | 319,502 | |
Commodity collars | | (Loss) gain on derivative instruments | | (15,929) | | | — | | | (15,929) | | | — | |
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 20202021 and December 31, 2019,2020, are presented in the following table.
| | | September 30, 2020 | | December 31, 2019 | | September 30, 2021 | | December 31, 2020 |
(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 | | | 93,774 | | | 0 | | | 93,774 | | | 0 | | | 0 | | | 0 | | | 0 | | |
Commodity swaps | | Commodity swaps | | $ | — | | | — | | | — | | | — | | | — | | | 13,050 | | | — | | | 13,050 | |
| | $ | 0 | | | 93,774 | | | 0 | | | 93,774 | | | 0 | | | 0 | | | 0 | | | 0 | | | $ | — | | | — | | | — | | | — | | | — | | | 13,050 | | | — | | | 13,050 | |
| Liabilities: | Liabilities: | | Liabilities: | |
Commodity derivative contracts | | $ | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 33,364 | | | 0 | | | 33,364 | | |
Nonqualified employee savings plans | | 16,169 | | | 0 | | | 0 | | | 16,169 | | | 17,035 | | | 0 | | | 0 | | | 17,035 | | |
Commodity collars | | Commodity collars | | $ | — | | | 15,929 | | | — | | | 15,929 | | | — | | | — | | | — | | | — | |
Nonqualified employee savings plan | | Nonqualified employee savings plan | | 17,180 | | | — | | | — | | | 17,180 | | | 14,988 | | | — | | | — | | | 14,988 | |
Commodity swaps | | Commodity swaps | | — | | | 354,093 | | | — | | | 354,093 | | | — | | | 102,675 | | | — | | | 102,675 | |
Contingent consideration | Contingent consideration | | 0 | | | 0 | | | 117,311 | | | 117,311 | | | 0 | | | 0 | | | 146,787 | | | 146,787 | | Contingent consideration | | — | | | — | | | 238,115 | | | 238,115 | | | — | | | — | | | 133,004 | | | 133,004 | |
| | $ | 16,169 | | | 0 | | | 117,311 | | | 133,480 | | | 17,035 | | | 33,364 | | | 146,787 | | | 197,186 | | | $ | 17,180 | | | 370,022 | | | 238,115 | | | 625,317 | | | 14,988 | | | 102,675 | | | 133,004 | | | 250,667 | |
The fair value of WTIcommodity (WTI crude oiloil) derivative contracts in 20202021 and 20192020 were based on active market quotes for WTI crude oil. The before tax income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contractsderivative instruments in the Consolidated Statements of Operations.
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management(Contd.)
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) expense in the Consolidated Statements of Operations. Any remaining contingentContingent consideration is payable will be due annually in years 20212022 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 September 30, 20202021 and December 31, 2019.2020.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 20192020 and September 30, 20202021 and the changes during the nine-month period ended September 30, 2020,2021, are presented net of taxes in the following table.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note M – Accumulated Other Comprehensive Loss (Contd.)
| | | | | | | | | | | | | | | | | | | | | | | |
(Thousands of dollars) | Foreign Currency Translation Gains (Losses) | | Retirement and Postretirement Benefit Plan Adjustments | | Deferred Loss on Interest Rate Derivative Hedges | | Total |
Balance at December 31, 2019 | $ | (353,252) | | | (218,015) | | | (2,894) | | | (574,161) | |
Components of other comprehensive income (loss): | | | | | | | |
Before reclassifications to income and retained earnings | (39,520) | | | (55,707) | | | 0 | | | (95,227) | |
Reclassifications to income | 0 | | | 10,488 | | ¹ | 905 | | ² | 11,393 | |
Net other comprehensive income (loss) | (39,520) | | | (45,219) | | | 905 | | | (83,834) | |
Balance at September 30, 2020 | $ | (392,772) | | | (263,234) | | | (1,989) | | | (657,995) | |
| | | | | | | | | | | | | | | | | | | | | | | |
(Thousands of dollars) | Foreign Currency Translation Gains (Losses) | | Retirement and Postretirement Benefit Plan Adjustments | | Deferred Loss on Interest Rate Derivative Hedges | | Total |
Balance at December 31, 2020 | $ | (324,011) | | | (275,632) | | | (1,690) | | | (601,333) | |
Components of other comprehensive income (loss): | | | | | | | |
Before reclassifications to income and retained earnings | 6,534 | | | — | | | — | | | 6,534 | |
Reclassifications to income | — | | | 12,935 | | ¹ | 1,690 | | ² | 14,625 | |
Net other comprehensive income (loss) | 6,534 | | | 12,935 | | | 1,690 | | | 21,159 | |
Balance at September 30, 2021 | $ | (317,477) | | | (262,697) | | | — | | | (580,174) | |
1 Reclassifications before taxes of $13,720 $16,282 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2020.2021. See Note H for additional information. Related income taxes of $3,232 $3,347 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2020.2021.
2 Reclassifications before taxes of $1,147 $2,140 are included in Interest expense, net, for the nine-month period ended September 30, 2020.2021. Related income taxes of $242 $450 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2020.2021. See Note L for additional information.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing changes;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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable laws and regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings.
The Biden administration has indicated that it intends to increase regulatory oversight of the oil and gas industry, with a focus on climate change and greenhouse gas emissions (including methane emissions). The Biden administration has issued a number of executive orders that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. The Biden administration has also issued orders related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardousHazardous 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 priorowners 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 and operational matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The CompanyMurphy USA Inc. has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.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/(loss),income, financial condition or liquidity in a future period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulationsadditional expenditures could require additional expendituresbe 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/(loss),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/ (loss),income, financial condition or liquidity in a future period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
NoteO– Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets at September 30, 2020 | | Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2019 |
(Millions of dollars) | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | $ | 7,028.0 | | | 330.8 | | | (172.6) | | | 656.8 | | | 170.8 | |
Canada | | 2,155.5 | | | 96.3 | | | (8.6) | | | 95.0 | | | (9.1) | |
Other | | 264.1 | | | 0 | | | (11.7) | | | 1.9 | | | (3.7) | |
Total exploration and production | | 9,447.6 | | | 427.1 | | | (192.9) | | | 753.7 | | | 158.0 | |
Corporate | | 1,002.1 | | | (5.2) | | | (72.9) | | | 63.4 | | | 0.3 | |
Assets/revenue/income (loss) from continuing operations | | 10,449.7 | | | 421.9 | | | (265.8) | | | 817.1 | | | 158.3 | |
Discontinued operations, net of tax | | 19.7 | | | 0 | | | (0.8) | | | 0 | | | 953.4 | |
Total | | $ | 10,469.4 | | | 421.9 | | | (266.6) | | | 817.1 | | | 1,111.7 | |
| | | | | | | | | | |
| | | | Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2019 |
| | | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | | | $ | 1,070.6 | | | (1,011.7) | | | 1,734.3 | | | 420.0 | |
Canada | | | | 245.2 | | | (35.0) | | | 323.8 | | | (7.5) | |
Other | | | | 1.8 | | | (73.0) | | | 7.9 | | | (35.4) | |
Total exploration and production | | | | 1,317.6 | | | (1,119.7) | | | 2,066.0 | | | 377.1 | |
Corporate | | | | 319.5 | | | 26.9 | | | 125.6 | | | (97.0) | |
Assets/revenue/income (loss) from continuing operations | | | | 1,637.1 | | | (1,092.8) | | | 2,191.6 | | | 280.1 | |
Discontinued operations, net of tax | | | | 0 | | | (6.9) | | | 0 | | | 1,027.6 | |
Total | | | | $ | 1,637.1 | | | (1,099.7) | | | 2,191.6 | | | 1,307.7 | |
1Additional details about results of oil and gas operations are presented in the table on pages 26 and 27.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note P – Acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Assets at September 30, 2021 | | Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2020 |
(Millions of dollars) | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | $ | 6,586.3 | | | 565.2 | | | 168.1 | | | 330.8 | | | (172.6) | |
Canada | | 2,241.2 | | | 124.6 | | | 73.9 | | | 96.3 | | | (8.6) | |
Other | | 264.6 | | | — | | | (5.2) | | | — | | | (11.7) | |
Total exploration and production | | 9,092.1 | | | 689.8 | | | 236.8 | | | 427.1 | | | (192.9) | |
Corporate | | 1,237.8 | | | (59.1) | | | (98.8) | | | (5.2) | | | (72.9) | |
Continuing operations | | 10,329.9 | | | 630.7 | | | 138.0 | | | 421.9 | | | (265.8) | |
Discontinued operations, net of tax | | 1.0 | | | — | | | (0.7) | | | — | | | (0.8) | |
Total | | $ | 10,330.9 | | | 630.7 | | | 137.3 | | | 421.9 | | | (266.6) | |
| | | | | | | | | | |
| | | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 |
(Millions of dollars) | | | External Revenues | | Income (Loss) | | External Revenues | | Income (Loss) |
Exploration and production ¹ | | | | | | | | | | |
United States | | | | 1,704.4 | | | 481.8 | | | 1,070.6 | | | (1,011.7) | |
Canada | | | | 349.2 | | | (37.7) | | | 245.2 | | | (35.0) | |
Other | | | | — | | | (22.5) | | | 1.8 | | | (73.0) | |
Total exploration and production | | | | 2,053.6 | | | 421.6 | | | 1,317.6 | | | (1,119.7) | |
Corporate | | | | (493.3) | | | (577.6) | | | 319.5 | | | 26.9 | |
Continuing operations | | | | 1,560.3 | | | (156.0) | | | 1,637.1 | | | (1,092.8) | |
Discontinued operations, net of tax | | | | — | | | (0.6) | | | — | | | (6.9) | |
Total | | | | 1,560.3 | | | (156.6) | | | 1,637.1 | | | (1,099.7) | |
LLOG Acquisition1:
In June 2019, the Company announced the completionAdditional details about results of a transaction with LLOG Exploration Offshore L.L.C.oil and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200 millionnatural gas operations are presented in the event that certain revenue thresholds are exceeded between 2019table on pages 25 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2019 period.
26.
Note Q – Restructuring Charges
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income during the three and nine months ended September 30, 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and 2 airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, 1 of the planes has been sold. All Restructuring charges have been recorded in the Corporate segment.
The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the three and nine months ended September 30, 2020:
| | | | | | | | |
(Thousands of dollars) | Three Months Ended September 30, 2020 | Nine Months Ended September 30, 2020 |
Severance | $ | 2,635 | | 22,502 | |
Pension and termination benefit charges | 0 | | 10,913 | |
Contract exit costs and other | 2,347 | | 12,964 | |
Restructuring charges | $ | 4,982 | | 46,379 | |
The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at September 30, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:
| | | | | |
(Thousands of dollars) | |
Restructuring accruals | $ | 28,814 | |
Utilizations | (19,635) | |
Liability at September 30, 2020 | $ | 9,179 | |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In 20202021, the continued spreadglobal distribution and administration of vaccinations in response to the ongoing coronavirus disease 2019 (COVID-19) pandemic has led to disruptionan improving global economic outlook and subsequently increased demand for oil and gas. Emerging COVID-19 variants, such as the Delta variant, continue to create uncertainty in the global economy and a weaknessoutlook, however in 2021 demand for crude oil. In the first quarter of 2020, certain major global suppliers of crude oil announcedand gas has remained resilient. The demand resilience has revealed an oil supply increases which resulted in a contributionshortage, and hence is applying upward pressure to the lower global commodity prices in the first quartercurrent and early second quarter. In early second quarter of 2020, thefuture oil and gas prices.
The OPEC+ group of oil producing countries agreed(OPEC+) continues to target increasing supply restrictions which helped supportby 0.4 million bpd a month, with aims to fully phase out prior cuts by September 2022, at the current rate of OPEC+ supply increases. In 2020 OPEC+ cut production by 10 million barrels per day (bpd) following the COVID-19 demand reduction. It has gradually reinstated supply so that the curtailments are approximately 5.8 million bpd at the end of September 2021. However, some members of the OPEC+ are falling short on supply increases.
Overall, the combination of OPEC+ supply constraints and the increase in demand driven by the global COVID-19 vaccine roll out has provided upward pressure to the oil price inwhich directly impacts the latter part of the second quarter and during the third quarter. Nevertheless, oil prices during the third quarter 2020 remained below average 2019 prices. The reduction in commodity pricesCompany’s product revenue from sales compared to 2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 35.one year ago.
For the three months ended September 30, 2020,2021, West Texas Intermediate (WTI) crude oil prices averaged approximately $41$70.56 per barrel (compared to $28$66.07 in the second quarter of 20202021 and $56$40.93 in the third quarter of 2019)2020). The closing price for WTI at the end of the third quarter of 20202021 was approximately $40$71.54 per barrel, reflecting a 34% reductionmodest increase from the second quarter 2021 closing price atand an 81% increase from the end of 2019.third quarter 2020 closing price. The average price in October 20202021 was $39.55$81.22 per barrel. As of close on November 4, 2020,2, 2021, the NYMEX WTI forward curve pricesprice for the remainder of 20202021 and 20212022 were $39.15$83.91 and $41.06$76.27 per barrel, respectively.
In the third quarter of 2021, the Company continued to delever by redeeming $150.0 million aggregate principal amount of its 6.875% senior notes due 2024 for the principal amount plus cash costs of $2.6 million. Earlier in 2021, the Company executed a series of financial transactions which redeemed the remaining notes due 2022 and issued new 7 year senior unsecured notes maturing in July 2028. The 2022 notes were redeemed for total use of funds of $619.5 million, which included redemption at par of $576.4 million, early retirement premium (make whole payment) of $34.2 million, and $8.9 million of accrued interest. The 2028 notes were issued for total proceeds of $550.0 million and closing costs of $8.1 million. The proceeds from issue are reported net of costs to issue on the Consolidated Balance Sheets.
In the third quarter of 2021, the Company acquired an additional 7.525% working interest at Terra Nova in Canada following a commercial agreement to sanction an asset life extension project. This transaction deferred an asset obligation at Terra Nova by approximately 10 years and decreased the obligation associated with the abandonment liability of the working interest before the acquisition by approximately $72 million.
For the three months ended September 30, 2021, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 14.5 thousand barrels of oil equivalent per day (including NCI). The Company invested $110.5 million in capital expenditures (on a value of work done basis) in the three months ended September 30, 2021. The Company reported net income from continuing operations of $138.0 million for the three months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of $28.9 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $44.1 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on contingent consideration of $22.4 million.
For the nine months ended September 30, 2021, the Company produced 170 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations; this includes the impact of Hurricane Ida on U.S. Gulf of Mexico production of 4.9 thousand barrels of oil equivalent per day (including NCI). The Company invested $568.7 million in capital expenditures (on a value of work done basis) in the nine months ended September 30, 2021, which included $18.0 million to fund the development of the King’s Quay Floating Production System (FPS). The FPS capital expenditures were reimbursed by Arclight in the first quarter of 2021 (see below). The Company reported net loss from continuing operations of $156.0 million for the nine months ended September 30, 2021. This amount includes income attributable to noncontrolling interest of $85.5 million, after-tax impairment charges of $128.0 million, an after-tax non-cash credit of $53.6 million related to the deferral of asset retirement obligations and after-tax losses on unrealized mark to market revaluations on commodity price swap and collar positions and contingent consideration of $180.5 million and $83.0 million, respectively.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Summary (contd.)
For the three months ended September 30, 2020, the Company produced 163 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $122.7 million in capital expenditures (on a value of work done basis), in the third quarter of 2020, which included $19.3 million to fund the development of the King’s Quay Floating Production System (FPS).FPS. The Company reported net loss from continuing operations of $265.8 million (which includes afor the third quarter of 2020. This amount included loss attributable to noncontrolling interest of $23.1 million) for the third quartermillion, after-tax impairment charges of 2020.$145.9 million and after-tax losses on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $54.8 million and $11.1 million, respectively.
For the nine months ended September 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $680.3 million in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2020, which included $80.7 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $1,092.8 million (which includes impairment charges of $854.2 million, net of tax, and afor the nine months ended September 30, 2020. This amount included loss attributable to noncontrolling interest of $122.9 million)million, after-tax impairment charges of $854.2 million and after-tax gains on unrealized mark to market revaluations on commodity price hedge positions and contingent consideration of $82.5 million and $23.3 million, respectively.
In the first quarter, the Company’s subsidiary "Murphy Exploration & Production Company USA" closed a transaction with ArcLight Capital Partners, LLC (ArcLight) for the nine months ended September 30, 2020.
For the three months ended September 30, 2019, the Company produced 203 thousand barrelssale of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $356.6 million in capital expenditures (on a value of work done basis)Murphy’s entire 50% interest in the third quarterKing’s Quay FPS and associated export lateral pipelines. The transaction reimbursed Murphy for its share of 2019. The Company reported net incomeproject costs from continuing operationsinception to closing with proceeds of $158.3 million (which includes income attributable to noncontrolling interest of $22.7 million) for the three months ended September 30, 2019.$267.7 million.
For the nine months ended September 30, 2019, the Company produced 179 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $2.3 billion in capital expenditures (on a value of work done basis) for the nine months ended September 30, 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $280.1 million (which includes income attributable to noncontrolling interest of $86.3 million) for the nine months ended September 30, 2019.
During the three-month and nine-month periods ended September 30, 2020, crude oil and condensate volumes from continuing operations were lower than the prior year period as a result of lower Eagle Ford Shale volumes (due to lower capital expenditures) and higher hurricane and storm downtime in the Gulf of Mexico. Revenue, compared to 2019, was also impacted by the lower average oil prices. The results are explained in more detail below.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations
Murphy’s income (loss) by type of business is presented below.
| | | Income (Loss) | | Income (Loss) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars) | (Millions of dollars) | 2020 | | 2019 | | 2020 | | 2019 | (Millions of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Exploration and production | Exploration and production | $ | (192.9) | | | 158.0 | | | (1,119.7) | | | 377.1 | | Exploration and production | $ | 236.8 | | | (192.9) | | | 421.6 | | | (1,119.7) | |
Corporate and other | Corporate and other | (72.9) | | | 0.3 | | | 26.9 | | | (97.0) | | Corporate and other | (98.8) | | | (72.9) | | | (577.6) | | | 26.9 | |
(Loss) income from continuing operations | (265.8) | | | 158.3 | | | (1,092.8) | | | 280.1 | | |
Income (loss) from continuing operations | | Income (loss) from continuing operations | 138.0 | | | (265.8) | | | (156.0) | | | (1,092.8) | |
Discontinued operations ¹ | Discontinued operations ¹ | (0.8) | | | 953.4 | | | (6.9) | | | 1,027.6 | | Discontinued operations ¹ | (0.7) | | | (0.8) | | | (0.6) | | | (6.9) | |
Net (loss) income including noncontrolling interest | $ | (266.6) | | | 1,111.7 | | | (1,099.7) | | | 1,307.7 | | |
Net income (loss) including noncontrolling interest | | Net income (loss) including noncontrolling interest | $ | 137.3 | | | (266.6) | | | (156.6) | | | (1,099.7) | |
1 The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing and Malaysian exploration and production operations as discontinued operations in its consolidated financial statements.
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
| | | | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars) | 2020 | | 2019 | | 2020 | | 2019 |
Exploration and production | | | | | | | |
United States | $ | (172.6) | | | 170.8 | | | (1,011.7) | | | 420.0 | |
Canada | (8.6) | | | (9.1) | | | (35.0) | | | (7.5) | |
Other | (11.7) | | | (3.7) | | | (73.0) | | | (35.4) | |
Total | $ | (192.9) | | | 158.0 | | | (1,119.7) | | | 377.1 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars) | 2021 | | 2020 | | 2021 | | 2020 |
Exploration and production | | | | | | | |
United States | $ | 168.1 | | | (172.6) | | | 481.8 | | | (1,011.7) | |
Canada | 73.9 | | | (8.6) | | | (37.7) | | | (35.0) | |
Other | (5.2) | | | (11.7) | | | (22.5) | | | (73.0) | |
Total | $ | 236.8 | | | (192.9) | | | 421.6 | | | (1,119.7) | |
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 September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars, except per barrel of oil equivalents sold) | (Millions of dollars, except per barrel of oil equivalents sold) | 2020 | | 2019 | | 2020 | | 2019 | (Millions of dollars, except per barrel of oil equivalents sold) | 2021 | | 2020 | | 2021 | | 2020 |
Net (loss) income attributable to Murphy (GAAP) | $ | (243.6) | | | 1,089.0 | | | (976.8) | | | 1,221.5 | | |
Income tax (benefit) expense | (62.6) | | | 18.8 | | | (248.9) | | | 38.7 | | |
Net income (loss) attributable to Murphy (GAAP) | | Net income (loss) attributable to Murphy (GAAP) | $ | 108.5 | | | (243.6) | | | (242.1) | | | (976.8) | |
Income tax expense (benefit) | | Income tax expense (benefit) | 36.8 | | | (62.6) | | | (62.5) | | | (248.9) | |
Interest expense, net | Interest expense, net | 45.2 | | | 44.9 | | | 124.9 | | | 145.1 | | Interest expense, net | 46.9 | | | 45.2 | | | 178.4 | | | 124.9 | |
Depreciation, depletion and amortization expense ¹ | Depreciation, depletion and amortization expense ¹ | 219.7 | | | 308.3 | | | 725.1 | | | 766.4 | | Depreciation, depletion and amortization expense ¹ | 182.8 | | | 219.7 | | | 588.4 | | | 725.1 | |
EBITDA attributable to Murphy (Non-GAAP) | EBITDA attributable to Murphy (Non-GAAP) | (41.3) | | | 1,461.0 | | | (375.7) | | | 2,171.7 | | EBITDA attributable to Murphy (Non-GAAP) | 375.0 | | | (41.3) | | | 462.2 | | | (375.7) | |
Mark-to-market (gain) loss on derivative instruments | | Mark-to-market (gain) loss on derivative instruments | (55.9) | | | 69.3 | | | 228.5 | | | (104.5) | |
Impairment of assets ¹ | Impairment of assets ¹ | 186.5 | | | — | | | 1,072.5 | | | — | | Impairment of assets ¹ | — | | | 186.5 | | | 171.3 | | | 1,072.5 | |
Mark-to-market loss (gain) on crude oil derivative contracts | 69.3 | | | (49.2) | | | (104.5) | | | (100.1) | | |
Mark-to-market loss (gain) on contingent consideration | Mark-to-market loss (gain) on contingent consideration | 14.0 | | | (28.4) | | | (29.5) | | | 0.5 | | Mark-to-market loss (gain) on contingent consideration | 28.4 | | | 14.0 | | | 105.1 | | | (29.5) | |
Asset retirement obligation (gains) losses | | Asset retirement obligation (gains) losses | (71.8) | | | — | | | (71.8) | | | — | |
Accretion of asset retirement obligations ¹ | | Accretion of asset retirement obligations ¹ | 10.8 | | | 10.8 | | | 30.8 | | | 31.2 | |
Unutilized rig charges | | Unutilized rig charges | 3.2 | | | 5.2 | | | 8.5 | | | 13.2 | |
Foreign exchange (gains) losses | | Foreign exchange (gains) losses | (2.8) | | | 0.8 | | | (1.5) | | | (2.5) | |
Discontinued operations loss | | Discontinued operations loss | 0.7 | | | 0.8 | | | 0.6 | | | 6.9 | |
Restructuring expenses | Restructuring expenses | 5.0 | | | — | | | 46.4 | | | — | | Restructuring expenses | — | | | 5.0 | | | — | | | 46.4 | |
Accretion of asset retirement obligations | 10.8 | | | 10.6 | | | 31.2 | | | 29.8 | | |
Unutilized rig charges | 5.2 | | | — | | | 13.2 | | | — | | |
Discontinued operations loss (income) | 0.8 | | | (953.4) | | | 6.9 | | | (1,027.6) | | |
Inventory loss | Inventory loss | — | | | — | | | 4.8 | | | — | | Inventory loss | — | | | — | | | — | | | 4.8 | |
Foreign exchange losses (gains) | 0.8 | | | 0.8 | | | (2.5) | | | 6.4 | | |
Business development transaction costs | — | | | 4.1 | | | — | | | 24.4 | | |
Write-off of previously suspended exploration wells | — | | | — | | | — | | | 13.2 | | |
Seal insurance proceeds | Seal insurance proceeds | (1.7) | | | (8.0) | | | (1.7) | | | (8.0) | | Seal insurance proceeds | — | | | (1.7) | | | — | | | (1.7) | |
| | Adjusted EBITDA attributable to Murphy (Non-GAAP) | Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 249.4 | | | 437.5 | | | 661.1 | | | 1,110.3 | | Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 287.6 | | | 249.4 | | | 933.7 | | | 661.1 | |
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 14,166 | | | 17,745 | | | 46,478 | | | 45,511 | | Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 14,219 | | | 14,166 | | | 43,536 | | | 46,478 | |
| Adjusted EBITDA per barrel of oil equivalents sold | Adjusted EBITDA per barrel of oil equivalents sold | $ | 17.61 | | | 24.65 | | | 14.22 | | | 24.40 | | Adjusted EBITDA per barrel of oil equivalents sold | $ | 20.23 | | | 17.61 | | | 21.45 | | | 14.22 | |
1 Depreciation, depletion, and amortization expense, used in the computation of EBITDA and 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 SEPTEMBER 30, 2021 AND 2020
| | | | | | | | | | | | | | | | | | | | | | | |
(Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Three Months Ended September 30, 2021 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 565.2 | | | 124.6 | | | — | | | 689.8 | |
Lease operating expenses | 96.7 | | | 33.4 | | | 0.1 | | | 130.2 | |
Severance and ad valorem taxes | 10.8 | | | 0.8 | | | — | | | 11.6 | |
Transportation, gathering and processing | 28.4 | | | 16.2 | | | — | | | 44.6 | |
Depreciation, depletion and amortization | 147.0 | | | 39.7 | | | 0.1 | | | 186.8 | |
| | | | | | | |
Accretion of asset retirement obligations | 9.3 | | | 2.9 | | | — | | | 12.2 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | 17.3 | | | — | | | — | | | 17.3 | |
Geological and geophysical | — | | | — | | | 0.3 | | | 0.3 | |
Other exploration | 1.3 | | | 0.1 | | | 0.5 | | | 1.9 | |
| 18.6 | | | 0.1 | | | 0.8 | | | 19.5 | |
Undeveloped lease amortization | 3.1 | | | 0.1 | | | 1.8 | | | 5.0 | |
Total exploration expenses | 21.7 | | | 0.2 | | | 2.6 | | | 24.5 | |
Selling and general expenses | 4.2 | | | 4.0 | | | 1.2 | | | 9.4 | |
Other ² | 39.1 | | | (71.7) | | | 2.0 | | | (30.6) | |
Results of operations before taxes | 208.0 | | | 99.1 | | | (6.0) | | | 301.1 | |
Income tax provisions (benefits) | 39.9 | | | 25.2 | | | (0.8) | | | 64.3 | |
Results of operations (excluding Corporate segment) | $ | 168.1 | | | 73.9 | | | (5.2) | | | 236.8 | |
| | | | | | | |
Three Months Ended September 30, 2020 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 330.8 | | | 96.3 | | | — | | | 427.1 | |
Lease operating expenses | 91.5 | | | 32.6 | | | 0.4 | | | 124.5 | |
Severance and ad valorem taxes | 6.4 | | | 0.3 | | | — | | | 6.7 | |
Transportation, gathering and processing | 29.3 | | | 12.0 | | | — | | | 41.3 | |
Depreciation, depletion and amortization | 166.2 | | | 59.6 | | | 0.5 | | | 226.3 | |
Accretion of asset retirement obligations | 9.4 | | | 1.4 | | | — | | | 10.8 | |
Impairment of assets | 205.1 | | | — | | | — | | | 205.1 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | 0.6 | | | — | | | — | | | 0.6 | |
Geological and geophysical | 0.1 | | | — | | | (0.1) | | | — | |
Other exploration | 0.6 | | | 0.1 | | | 3.6 | | | 4.3 | |
| 1.3 | | | 0.1 | | | 3.5 | | | 4.9 | |
Undeveloped lease amortization | 4.9 | | | 0.1 | | | 2.3 | | | 7.3 | |
Total exploration expenses | 6.2 | | | 0.2 | | | 5.8 | | | 12.2 | |
Selling and general expenses | 5.3 | | | 3.4 | | | 1.6 | | | 10.3 | |
Other | 22.5 | | | (1.5) | | | 2.5 | | | 23.5 | |
Results of operations before taxes | (211.1) | | | (11.7) | | | (10.8) | | | (233.6) | |
Income tax (benefits) provisions | (38.5) | | | (3.1) | | | 0.9 | | | (40.7) | |
Results of operations (excluding Corporate segment) | $ | (172.6) | | | (8.6) | | | (11.7) | | | (192.9) | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREENINE MONTHS ENDED SEPTEMBER 30, 20202021 AND 20192020
| (Millions of dollars) | (Millions of dollars) | United States 1 | | Canada | | Other | | Total | (Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Three Months Ended September 30, 2020 | | | | | | | | |
Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 | | | | | | | |
Oil and gas sales and other operating revenues | Oil and gas sales and other operating revenues | $ | 330.8 | | | 96.3 | | | — | | | 427.1 | | Oil and gas sales and other operating revenues | $ | 1,704.4 | | | 349.2 | | | — | | | 2,053.6 | |
Lease operating expenses | Lease operating expenses | 91.5 | | | 32.6 | | | 0.4 | | | 124.5 | | Lease operating expenses | 303.3 | | | 100.0 | | | 0.4 | | | 403.7 | |
Severance and ad valorem taxes | Severance and ad valorem taxes | 6.4 | | | 0.3 | | | — | | | 6.7 | | Severance and ad valorem taxes | 30.6 | | | 1.6 | | | — | | | 32.2 | |
Transportation, gathering and processing | Transportation, gathering and processing | 29.3 | | | 12.0 | | | — | | | 41.3 | | Transportation, gathering and processing | 90.5 | | | 46.7 | | | — | | | 137.2 | |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | 166.2 | | | 59.6 | | | 0.5 | | | 226.3 | | Depreciation, depletion and amortization | 476.6 | | | 128.0 | | | 1.1 | | | 605.7 | |
Impairments of assets | 205.1 | | | — | | | — | | | 205.1 | | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | 9.4 | | | 1.4 | | | — | | | 10.8 | | Accretion of asset retirement obligations | 27.5 | | | 7.4 | | | — | | | 34.9 | |
Impairment of assets | | Impairment of assets | — | | | 171.3 | | | — | | | 171.3 | |
Exploration expenses | | Exploration expenses | |
Dry holes and previously suspended exploration costs | | Dry holes and previously suspended exploration costs | 17.9 | | | — | | | — | | | 17.9 | |
Geological and geophysical | | Geological and geophysical | 2.7 | | | — | | | 1.3 | | | 4.0 | |
Other exploration | | Other exploration | 4.2 | | | 0.2 | | | 9.6 | | | 14.0 | |
| | | 24.8 | | | 0.2 | | | 10.9 | | | 35.9 | |
Undeveloped lease amortization | | Undeveloped lease amortization | 7.9 | | | 0.2 | | | 5.8 | | | 13.9 | |
Total exploration expenses | | Total exploration expenses | 32.7 | | | 0.4 | | | 16.7 | | | 49.8 | |
Selling and general expenses | | Selling and general expenses | 15.0 | | | 12.0 | | | 4.7 | | | 31.7 | |
Other ² | | Other ² | 133.5 | | | (67.7) | | | (1.2) | | | 64.6 | |
Results of operations before taxes | | Results of operations before taxes | 594.7 | | | (50.5) | | | (21.7) | | | 522.5 | |
Income tax provisions (benefits) | | Income tax provisions (benefits) | 112.9 | | | (12.8) | | | 0.8 | | | 100.9 | |
Results of operations (excluding Corporate segment) | | Results of operations (excluding Corporate segment) | $ | 481.8 | | | (37.7) | | | (22.5) | | | 421.6 | |
| Nine months ended September 30, 2020 | | Nine months ended September 30, 2020 | |
Oil and gas sales and other operating revenues | | Oil and gas sales and other operating revenues | $ | 1,070.6 | | | 245.2 | | | 1.8 | | | 1,317.6 | |
Lease operating expenses | | Lease operating expenses | 386.5 | | | 90.6 | | | 1.2 | | | 478.3 | |
Severance and ad valorem taxes | | Severance and ad valorem taxes | 21.6 | | | 1.0 | | | — | | | 22.6 | |
Transportation, gathering and processing | | Transportation, gathering and processing | 95.4 | | | 31.4 | | | — | | | 126.8 | |
Depreciation, depletion and amortization | | Depreciation, depletion and amortization | 589.5 | | | 161.3 | | | 1.5 | | | 752.3 | |
Accretion of asset retirement obligations | | Accretion of asset retirement obligations | 27.1 | | | 4.1 | | | — | | | 31.2 | |
Impairment of assets | | Impairment of assets | 1,152.5 | | | — | | | 39.7 | | | 1,192.2 | |
Exploration expenses | Exploration expenses | | Exploration expenses | |
Dry holes and previously suspended exploration costs | Dry holes and previously suspended exploration costs | 0.6 | | | — | | | — | | | 0.6 | | Dry holes and previously suspended exploration costs | 8.3 | | | — | | | — | | | 8.3 | |
Geological and geophysical | Geological and geophysical | 0.1 | | | — | | | (0.1) | | | — | | Geological and geophysical | 9.4 | | | 0.1 | | | 4.1 | | | 13.6 | |
Other exploration | Other exploration | 0.6 | | | 0.1 | | | 3.6 | | | 4.3 | | Other exploration | 4.3 | | | 0.4 | | | 13.1 | | | 17.8 | |
| | 1.3 | | | 0.1 | | | 3.5 | | | 4.9 | | | 22.0 | | | 0.5 | | | 17.2 | | | 39.7 | |
Undeveloped lease amortization | Undeveloped lease amortization | 4.9 | | | 0.1 | | | 2.3 | | | 7.3 | | Undeveloped lease amortization | 14.8 | | | 0.3 | | | 6.9 | | | 22.0 | |
Total exploration expenses | Total exploration expenses | 6.2 | | | 0.2 | | | 5.8 | | | 12.2 | | Total exploration expenses | 36.8 | | | 0.8 | | | 24.1 | | | 61.7 | |
Selling and general expenses | Selling and general expenses | 5.3 | | | 3.4 | | | 1.6 | | | 10.3 | | Selling and general expenses | 16.6 | | | 13.2 | | | 5.5 | | | 35.3 | |
Other | Other | 22.5 | | | (1.5) | | | 2.5 | | | 23.5 | | Other | 1.0 | | | (2.5) | | | 1.4 | | | (0.1) | |
Results of operations before taxes | Results of operations before taxes | (211.1) | | | (11.7) | | | (10.8) | | | (233.6) | | Results of operations before taxes | (1,256.4) | | | (54.7) | | | (71.6) | | | (1,382.7) | |
Income tax provisions (benefits) | Income tax provisions (benefits) | (38.5) | | | (3.1) | | | 0.9 | | | (40.7) | | Income tax provisions (benefits) | (244.7) | | | (19.7) | | | 1.4 | | | (263.0) | |
Results of operations (excluding Corporate segment) | Results of operations (excluding Corporate segment) | $ | (172.6) | | | (8.6) | | | (11.7) | | | (192.9) | | Results of operations (excluding Corporate segment) | $ | (1,011.7) | | | (35.0) | | | (73.0) | | | (1,119.7) | |
| | | | | | | | |
Three Months Ended September 30, 2019 | | |
Oil and gas sales and other operating revenues | $ | 656.8 | | | 95.0 | | | 1.9 | | | 753.7 | | |
Lease operating expenses | 116.2 | | | 31.2 | | | 0.2 | | | 147.6 | | |
Severance and ad valorem taxes | 13.4 | | | 0.4 | | | — | | | 13.8 | | |
Transportation, gathering and processing | 44.1 | | | 10.2 | | | — | | | 54.3 | | |
Depreciation, depletion and amortization | 253.5 | | | 65.3 | | | 0.6 | | | 319.4 | | |
Accretion of asset retirement obligations | 9.0 | | | 1.6 | | | — | | | 10.6 | | |
Exploration expenses | | |
Dry holes and previously suspended exploration costs | (0.1) | | | — | | | — | | | (0.1) | | |
Geological and geophysical | 0.2 | | | — | | | 0.2 | | | 0.4 | | |
Other exploration | 1.5 | | | 0.1 | | | 3.8 | | | 5.4 | | |
| 1.6 | | | 0.1 | | | 4.0 | | | 5.7 | | |
Undeveloped lease amortization | 5.2 | | | 0.3 | | | 1.0 | | | 6.5 | | |
Total exploration expenses | 6.8 | | | 0.4 | | | 5.0 | | | 12.2 | | |
Selling and general expenses | 22.7 | | | 7.6 | | | 5.6 | | | 35.9 | | |
Other | (21.0) | | | (7.3) | | | 0.5 | | | (27.8) | | |
Results of operations before taxes | 212.1 | | | (14.4) | | | (10.0) | | | 187.7 | | |
Income tax provisions (benefits) | 41.3 | | | (5.3) | | | (6.3) | | | 29.7 | | |
Results of operations (excluding Corporate segment) | $ | 170.8 | | | (9.1) | | | (3.7) | | | 158.0 | | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the nine months ended September 30, 2021, Canada includes $71.8 million of income related to the deferral of an asset retirement obligation at Terra Nova.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2020 AND 2019
| | | | | | | | | | | | | | | | | | | | | | | |
(Millions of dollars) | United States 1 | | Canada | | Other | | Total |
Nine Months Ended September 30, 2020 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 1,070.6 | | | 245.2 | | | 1.8 | | | 1,317.6 | |
Lease operating expenses | 386.5 | | | 90.6 | | | 1.2 | | | 478.3 | |
Severance and ad valorem taxes | 21.6 | | | 1.0 | | | — | | | 22.6 | |
Transportation, gathering and processing | 95.4 | | | 31.4 | | | — | | | 126.8 | |
Depreciation, depletion and amortization | 589.5 | | | 161.3 | | | 1.5 | | | 752.3 | |
Impairment of assets | 1,152.5 | | | — | | | 39.7 | | | 1,192.2 | |
Accretion of asset retirement obligations | 27.1 | | | 4.1 | | | — | | | 31.2 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | 8.3 | | | — | | | — | | | 8.3 | |
Geological and geophysical | 9.4 | | | 0.1 | | | 4.1 | | | 13.6 | |
Other exploration | 4.3 | | | 0.4 | | | 13.1 | | | 17.8 | |
| 22.0 | | | 0.5 | | | 17.2 | | | 39.7 | |
Undeveloped lease amortization | 14.8 | | | 0.3 | | | 6.9 | | | 22.0 | |
Total exploration expenses | 36.8 | | | 0.8 | | | 24.1 | | | 61.7 | |
Selling and general expenses | 16.6 | | | 13.2 | | | 5.5 | | | 35.3 | |
Other | 1.0 | | | (2.5) | | | 1.4 | | | (0.1) | |
Results of operations before taxes | (1,256.4) | | | (54.7) | | | (71.6) | | | (1,382.7) | |
Income tax provisions (benefits) | (244.7) | | | (19.7) | | | 1.4 | | | (263.0) | |
Results of operations (excluding Corporate segment) | $ | (1,011.7) | | | (35.0) | | | (73.0) | | | (1,119.7) | |
| | | | | | | |
Nine months ended September 30, 2019 | | | | | | | |
Oil and gas sales and other operating revenues | $ | 1,734.3 | | | 323.8 | | | 7.9 | | | 2,066.0 | |
Lease operating expenses | 308.3 | | | 107.1 | | | 1.1 | | | 416.5 | |
Severance and ad valorem taxes | 36.0 | | | 1.0 | | | — | | | 37.0 | |
Transportation, gathering and processing | 103.4 | | | 25.3 | | | — | | | 128.7 | |
Depreciation, depletion and amortization | 618.6 | | | 181.6 | | | 2.9 | | | 803.1 | |
Accretion of asset retirement obligations | 25.2 | | | 4.6 | | | — | | | 29.8 | |
Exploration expenses | | | | | | | |
Dry holes and previously suspended exploration costs | (0.2) | | | — | | | 13.1 | | | 12.9 | |
Geological and geophysical | 16.1 | | | — | | | 8.1 | | | 24.2 | |
Other exploration | 5.5 | | | 0.3 | | | 10.9 | | | 16.7 | |
| 21.4 | | | 0.3 | | | 32.1 | | | 53.8 | |
Undeveloped lease amortization | 18.0 | | | 1.0 | | | 2.7 | | | 21.7 | |
Total exploration expenses | 39.4 | | | 1.3 | | | 34.8 | | | 75.5 | |
Selling and general expenses | 52.9 | | | 21.3 | | | 17.3 | | | 91.5 | |
Other | 37.5 | | | (6.9) | | | 0.9 | | | 31.5 | |
Results of operations before taxes | 513.0 | | | (11.5) | | | (49.1) | | | 452.4 | |
Income tax provisions (benefits) | 93.0 | | | (4.0) | | | (13.7) | | | 75.3 | |
Results of operations (excluding Corporate segment) | $ | 420.0 | | | (7.5) | | | (35.4) | | | 377.1 | |
1 Includes results attributable to a noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Exploration and Production
Third quarter 20202021 vs. 20192020
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of 20202020. Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A: $19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of $170.8 millionHurricane Ida in the third quarter of 2019. Results were $343.4 million unfavorable2021 is offset by the impact of multiple storms that occurred in the 2020third quarter compared to the 2019 periodof 2020. Lower impairment charges were due to lower revenues ($326.0 million) and higher impairment charges ($205.1 million), partially offset by lower depreciation, depletion and amortization ($87.3 million), income tax expense ($79.8 million), lease operating expenses ($24.7 million), general and administrative (G&A: $17.4 million), and transportation, gathering, and processing expenses ($14.8 million). Lower revenues were primarily due to lower commodity prices, lower Eagle Ford Shale volumes (due to lower capital expenditures), and lower volumesrecognized in the U.S. Gulf of Mexico (as a result of shut-ins dueprior period related to hurricane activity in the 2020 quarter). The impairment charge in the quarter relates to the Gulf of Mexico Cascade & Chinook field which, primarily asand no such charges in current period. Lower DD&A is a result of lower commodity prices and lower capital expenditure plans, was written downthe prior year impairment charge reducing the depreciable asset base. Higher income tax expense is a result of pre-tax profits principally due to its expected future value. Lower depreciationthe recovering oil price. Higher other operating expense wasis primarily due to lower depreciation rates following the impairment charges incurred in the first quarterunfavorable mark to market revaluation on contingent consideration (as a result of 2020 and lower sales volume. Lower lease operating expense was primarily attributablehigher commodity prices) related to wells being shut-in in theprior Gulf of Mexico and certain cost-savings initiatives taken across all businesses. Lower G&A(GOM) acquisitions. Higher exploration expense is primarily due to cost reductions and lower headcount as a result of restructuring (primarily closingdry hole costs related to Silverback in the El Dorado and Calgary offices).current period.
Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter 2020 compared to a loss of $9.1 million in the 2019 quarter.2020. Results were favorable $0.5$82.5 million compared to the 20192020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($1.328.3 million), and lower depreciation and amortizationDD&A ($5.7 million), higher tax benefit ($2.219.9 million), partially offset by lower other operating incomehigher tax expense ($5.828.3 million), and higher transportation, gathering and processing expenses ($1.8 million), and higher lease operating expenses ($1.44.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Kaybob, and Placid (higher AECO prices in the quarter).Montney. Lower depreciation expenseDD&A is due to lower production volumes at TupperKaybob Duvernay due to normal well decline. Higher transportation, gathering and Terra-Nova (shut-in starting in December 2019). Terra Nova isprocessing costs are due to higher gas processing and downstream transportation capacity, which are expected to be shut-in forutilized by growth at Tupper Montney in the remainder of 2020 for Asset Integrity work.future.
Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020 compared to a net a loss of $3.7 million in the prior year quarter.2020. The result was $8.0$6.5 million unfavorablefavorable in the 20202021 period versus 20192020 primarily due higher prior period revenuelower exploration expenses in BruneiBrazil and a prior year income tax credit related to Vietnam exploration spend.Mexico.
Nine months 2021 vs. 2020 vs.2019
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020 compared to income of $420 million in the first nine months of 2019.2020. Results were $1,431.7$1,493.5 million unfavorablefavorable in the 20202021 period compared to the 20192020 period primarily due to anno impairment chargecharges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($1,152.5633.8 million), lower revenuesDD&A ($663.7112.9 million), higherlower lease operating expenses ($78.2(LOE: $83.2 million), partially offset by lowerhigher income tax expense ($337.7357.6 million), and higher other operating expense ($36.5 million), G&A ($36.3 million), depreciation, depletion and amortization (DD&A: $29.1 million), and transportation, gathering, and processing charges ($8.0132.5 million). The impairment charge isin the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of decreasedlower oil demand (COVID-19 impact) and increasedabundant oil supply (as discussed above). Based on an evaluationat the time of expected future cash flows from properties asthe assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. The production impact of September 30, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recordedHurricane Ida in the future.third quarter of 2021 is offset by the impact of multiple storms that occurred in 2020. Lower revenuesDD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to lower commodity prices year over year and lower volumeshigher GOM workover costs in the U.S. Gulf of Mexico (as a result of shut-ins related to hurricanes and storms). Higher lease operating expenses were due primarily to well workoversprior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). LowerHigher income tax expense is a result of higher pre-tax losses driven by the impairment chargeincome principally due to higher oil price and lower commodity prices. LowerDD&A and LOE. Higher other operating expense is primarily due to a favorablean unfavorable mark to market revaluation on contingent consideration (as($105.1 million; as a result of lowerhigher commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($29.5 million). Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).GOM acquisitions.
Canadian E&P operations reported a loss of $37.7 million in the first nine months of 2021 compared to a loss of $35.0 million in the first nine months of 2020 compared2020. Results were comparable year over year. 2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue ($104.0 million) and lower DD&A ($33.3 million) offset by higher transportation, gathering and processing expenses ($15.3 million) and lease operating expenses ($9.4 million). Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss of $7.5$22.5 million in the first nine months of 2019.2021 compared to a loss of $73.0 million in the prior year. Results were unfavorable $27.5$50.5 million favorable compared to the 20192020 period primarily due to lower revenue ($78.6 million)no repeat of an impairment charge of $39.7 million in the prior year.
Corporate
Third quarter 2021 vs. 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020. The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $59.2 million loss; 2020: $5.3 million loss), partially offset by lower lease operating expenseimpairment charges ($16.514.1 million), higher tax benefits ($5.7 million), lower DD&Arestructuring charges ($20.35.0 million), and lower DD&A ($2.3 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Higher income tax charges ($15.7 million). Lower revenues werebenefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.
Nine months 2021 vs. 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $577.6 million in the first nine months of 2021 compared to earnings of $26.9 million in the first nine months of 2020. The $604.5 million unfavorable variance is primarily due to realized and unrealized losses on derivative instruments in 2021 compared to gains in 2020 (2021: $499.8 million loss; 2020: $319.5 million gain), and higher interest expense ($54.1 million), partially offset by higher tax benefits ($177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $74.87 and for 2022 was $70.87 (versus swap contract fixed hedge prices of $42.77 and $44.88, respectively). Interest charges are higher in 2021primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022. Higher income tax benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.
Production Volumes and Prices
Third quarter 2021 vs. 2020
Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020. U.S. Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms. The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020.
Average crude oil and condensate prices versusproduction from continuing operations was 88,245 barrels per day in the prior year and a shut-in at Terra Nova for Asset Integrity work (startingthird quarter of 2021 compared to 95,391 barrels per day in December 2019 and expectedthe third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to continue through 2020 full year). Lower lease operating expenses andKaybob Duvernay well decline), lower DD&A werevolumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of lower sales.Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Other international E&P operations reported a loss from continuing operations of $73 million in the first nine months of 2020 compared to a net loss of $35.4 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.
Corporate
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income. These costs include severance, relocation, IT costs, pension curtailment, termination charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale as of September 30, 2020. Subsequent to period end, one of the planes has been sold.
Third quarter 2020 vs. 2019
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $72.9 million in the third quarter 2020 compared to net income of $0.3 million in the 2019 quarter. The $73.2 million unfavorable variance is principally due to 2020 mark to market losses on forward swap commodity contracts ($69.4 million) compared to gains on forward contracts ($49.2 million) in the third quarter of 2019, impairment of the El Dorado office building ($14.1 million), and restructuring charges ($5.0 million), partially offset by higher realized gains on forward commodity contracts ($50.1 million) and a higher tax credit ($10.9 million). Losses on forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with a fixed price. Higher realized gains on forward commodity contracts are due to lower prices versus the fixed contract price.
Nine months 2020 vs. 2019
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported earnings of $26.9 million in the first nine months of 2020 compared to a loss of $97.0 million in the first nine months of 2019. The $123.9 million favorable variance is primarily due to higher realized gains on forward swap commodity contracts ($194.0 million), lower interest charges ($20.6 million), lower G&A ($15.7 million), and partially offset by higher tax charges ($50.7 million) and restructuring charges ($46.4 million) related to the closure of the El Dorado and Calgary offices. Higher realized gains on forward swap commodity contracts are due to lower market pricing whereby the contract provides the Company with a fixed price. Interest charges are lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020. As of September 30, 2020, the average forward NYMEX WTI price for the remainder of 2020 was $40.35 and for 2021 was $42.21 (versus fixed hedge prices of $56.42 and $43.31; see below).
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Production Volumes and Prices
Third quarter 2020 vs. 2019
Total hydrocarbon production from continuing operations averaged 162,824 barrels of oil equivalent per day in the third quarter of 2020, which represented a 20% decrease from the 203,035 barrels per day produced in third quarter 2019. The decrease was principally due to GOM shut-in production due to hurricanes (14.2 MBOED) and lower Eagle Ford Shale production (16.2 MBOED, as a result of lower capex spend at this property).
Average crude oil and condensate production from continuing operations was 95,391 barrels per day in the third quarter of 2020 compared to 122,950 barrels per day in the third quarter of 2019. The decrease of 27,559 barrels per day was principally due to lower Eagle Ford Shale production due to lower capital expenditures (15,731 barrels per day) and lower volumes in the Gulf of Mexico (14,066 barrels per day) due to GOM shut-in production due to hurricanes (11.1 MBOED). On a worldwide basis, the Company’s crude oil and condensate prices averaged $39.79$68.88 per barrel in the third quarter 20202021 compared to $59.47$39.79 per barrel in the 20192020 period, a decreasean increase of 33%73% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 10,52310,391 barrels per day in the third quarter 20202021 compared to 13,60110,523 barrels per day in the 20192020 period. The average sales price for U.S. NGL was $14.78$32.01 per barrel in the 20202021 quarter compared to $13.26$13.91 per barrel in 2019.2020. The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in the 2020 quarter compared to $21.03 per barrel in 2019.2020. NGL prices are higher in Canada due to the higher value of the product produced at the Kaybob Duvernay and Placid Montney assets.
Natural gas salesproduction volumes from continuing operations averaged 341387.5 million cubic feet per day (MMCFD) in the third quarter 20202021 compared to 399341.5 MMCFD in 2019.2020. The decreaseincrease of 5746 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico (20(7 MMCFD) and lowerin the Eagle Ford Shale (4 MMCFD). Higher natural gas volumes in Canada (36 MMCFD).are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Lower volumes in the Gulf of Mexico are principally due to GOM shut-in production due to hurricanes. Lower volumes in Canada are due to normal well decline and no additional wells in third quarterfacility shut-ins as a result of 2020.Hurricane Ida.
Natural gas prices for the total Company averaged $1.78$2.78 per thousand cubic feet (MCF) in the 20202021 quarter, versus $1.46$1.78 per MCF average in the same quarter of 2019.2020. Average natural gas prices in the USU.S. and Canada in the quarter were $1.94$3.99 and $1.74$2.47 per MCF, respectively.
Nine months 20202021 vs. 20192020
Total hydrocarbon production from all E&P continuing operations averaged 180,443170,209 barrels of oil equivalent per day in the first nine months of 2020,2021, which represented a 1% increase6% decrease from the 178,658180,443 barrels per day produced in the first nine months of 2019.2020. The increasedecrease in production is principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.lower capital expenditures throughout 2020 to support generating positive free cashflow.
Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020 compared to 110,762 barrels per day in the first nine months of 2019.2020. The decrease of 2,08410,364 barrels per day was principally due to lower Eagle Ford Shale production (5,311 barrels per day), offset by higher volumes in the Gulf of Mexico (3,111production (5,472 barrels per day) due to temporary operational issues at the acquisitionCascade & Chinook and Kodiak fields in the first quarter of assets2021 and facility shut-ins as parta result of Hurricane Ida in the LLOG acquisition.third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged $36.88$64.19 per barrel in the first nine months of 20202021 compared to $60.94$36.88 per barrel in the 20192020 period, a decreasean increase of 39%74% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 11,90110,498 barrels per day in the first nine months of 20202021 compared to 10,99011,901 barrels per day in the 20192020 period. The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in 2020 compared to $15.22 per barrel in 2019.2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 per barrel in 2020 compared to $27.50 per barrel in 2019.2020. NGL prices are higher in Canada due to the higher value of the product produced at the Kaybob Duvernay and Placid Montney assets.
Natural gas sales volumes from continuing operations averaged 359368.4 million cubic feet per day (MMCFD) in the first nine months of 20202021 compared to 341359.2 MMCFD in 2019.2020. The increase of 189.2 MMCFD was a primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (24(4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). HigherLower volumes in the Gulf of Mexico are principally due to temporary operational issues at the acquisitionCascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of assets related toa winter storm impacting Eagle Ford Shale production in the LLOG transaction.
first quarter of 2021. Natural gas prices for the total Company averaged $1.68$2.56 per thousand cubic feet (MCF) in the first nine months of 2020,2021, versus $1.72$1.68 per MCF average in the same period of 2019.2020. Average natural gas prices in the USU.S. and Canada in the quarter were $1.87$3.26 and $1.62,$2.33, respectively.
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 contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 20202021 and 2019.2020.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Barrels per day unless otherwise noted | Barrels per day unless otherwise noted | 2020 | | 2019 | | 2020 | | 2019 | Barrels per day unless otherwise noted | 2021 | | 2020 | | 2021 | | 2020 |
Continuing operations | Continuing operations | | | | | | | | | Continuing operations | | | | | | | | |
Net crude oil and condensate | Net crude oil and condensate | | Net crude oil and condensate | |
United States | United States | Onshore | 24,851 | | | 40,582 | | | 27,945 | | | 33,256 | | United States | Onshore | 26,193 | | | 24,851 | | | 26,552 | | | 27,945 | |
| | Gulf of Mexico 1 | 56,517 | | | 70,583 | | | 67,377 | | | 64,266 | | | Gulf of Mexico 1 | 53,011 | | | 56,517 | | | 61,905 | | | 67,377 | |
Canada | Canada | Onshore | 9,595 | | | 7,101 | | | 8,106 | | | 6,503 | | Canada | Onshore | 4,963 | | | 9,595 | | | 5,598 | | | 8,106 | |
| | Offshore | 4,428 | | | 4,333 | | | 5,136 | | | 6,302 | | | Offshore | 3,779 | | | 4,428 | | | 4,016 | | | 5,136 | |
Other | Other | | — | | | 351 | | | 114 | | | 435 | | Other | | 299 | | | — | | | 243 | | | 114 | |
Total net crude oil and condensate - continuing operations | Total net crude oil and condensate - continuing operations | 95,391 | | | 122,950 | | | 108,678 | | | 110,762 | | Total net crude oil and condensate - continuing operations | 88,245 | | | 95,391 | | | 98,314 | | | 108,678 | |
Net natural gas liquids | Net natural gas liquids | | | | | | | | | Net natural gas liquids | | | | | | | | |
United States | United States | Onshore | 5,489 | | | 5,582 | | | 5,459 | | | 5,621 | | United States | Onshore | 5,847 | | | 5,489 | | | 5,043 | | | 5,459 | |
| | Gulf of Mexico 1 | 3,521 | | | 6,597 | | | 5,131 | | | 4,172 | | | Gulf of Mexico 1 | 3,459 | | | 3,521 | | | 4,296 | | | 5,131 | |
Canada | Canada | Onshore | 1,513 | | | 1,422 | | | 1,311 | | | 1,197 | | Canada | Onshore | 1,085 | | | 1,513 | | | 1,159 | | | 1,311 | |
Total net natural gas liquids - continuing operations | Total net natural gas liquids - continuing operations | 10,523 | | | 13,601 | | | 11,901 | | | 10,990 | | Total net natural gas liquids - continuing operations | 10,391 | | | 10,523 | | | 10,498 | | | 11,901 | |
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 | 27,520 | | | 29,122 | | | 29,054 | | | 30,203 | | United States | Onshore | 31,478 | | | 27,520 | | | 27,750 | | | 29,054 | |
| | Gulf of Mexico 1 | 53,046 | | | 72,897 | | | 67,850 | | | 44,029 | | | Gulf of Mexico 1 | 46,339 | | | 53,046 | | | 63,557 | | | 67,850 | |
Canada | Canada | Onshore | 260,895 | | | 296,883 | | | 262,279 | | | 267,205 | | Canada | Onshore | 309,709 | | | 260,895 | | | 277,077 | | | 262,279 | |
Total net natural gas - continuing operations | Total net natural gas - continuing operations | 341,461 | | | 398,902 | | | 359,183 | | | 341,437 | | Total net natural gas - continuing operations | 387,526 | | | 341,461 | | | 368,384 | | | 359,183 | |
Total net hydrocarbons - continuing operations including NCI 2,3 | Total net hydrocarbons - continuing operations including NCI 2,3 | 162,824 | | | 203,035 | | | 180,443 | | | 178,658 | | Total net hydrocarbons - continuing operations including NCI 2,3 | 163,224 | | | 162,824 | | | 170,209 | | | 180,443 | |
Noncontrolling interest | Noncontrolling interest | | | | | | | | | Noncontrolling interest | | | | | | | | |
Net crude oil and condensate – barrels per day | Net crude oil and condensate – barrels per day | (9,298) | | | (10,322) | | | (10,674) | | | (11,215) | | Net crude oil and condensate – barrels per day | (7,546) | | | (9,298) | | | (8,834) | | | (10,674) | |
Net natural gas liquids – barrels per day | Net natural gas liquids – barrels per day | (327) | | | (478) | | | (443) | | | (496) | | Net natural gas liquids – barrels per day | (243) | | | (327) | | | (322) | | | (443) | |
Net natural gas – thousands of cubic feet per day | (3,269) | | | (3,403) | | | (4,137) | | | (3,933) | | |
Net natural gas – thousands of cubic feet per day 2 | | Net natural gas – thousands of cubic feet per day 2 | (2,331) | | | (3,269) | | | (3,498) | | | (4,137) | |
Total noncontrolling interest | Total noncontrolling interest | (10,170) | | | (11,367) | | | (11,807) | | | (12,367) | | Total noncontrolling interest | (8,178) | | | (10,170) | | | (9,739) | | | (11,807) | |
Total net hydrocarbons - continuing operations excluding NCI 2,3 | Total net hydrocarbons - continuing operations excluding NCI 2,3 | 152,654 | | | 191,668 | | | 168,636 | | | 166,292 | | Total net hydrocarbons - continuing operations excluding NCI 2,3 | 155,046 | | | 152,654 | | | 160,470 | | | 168,636 | |
Discontinued operations | | |
Net crude oil and condensate – barrels per day | — | | | 1,748 | | | — | | | 16,331 | | |
Net natural gas liquids – barrels per day | — | | | 37 | | | — | | | 434 | | |
Net natural gas – thousands of cubic feet per day 2 | — | | | 9,624 | | | — | | | 67,863 | | |
Total discontinued operations | — | | | 3,389 | | | — | | | 28,076 | | |
Total net hydrocarbons produced excluding NCI 2,3 | 152,654 | | | 195,057 | | | 168,636 | | | 194,367 | | |
| |
1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains hydrocarbons sold during the three-month and nine-month periods ended September 30, 2020 and 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Barrels per day unless otherwise noted | 2020 | | 2019 | | 2020 | | 2019 |
Continuing operations | | | | | | | | |
Net crude oil and condensate | | | | | | | |
United States | Onshore | 24,851 | | | 40,582 | | | 27,945 | | | 33,256 | |
| Gulf of Mexico 1 | 57,756 | | | 71,380 | | | 68,436 | | | 64,532 | |
Canada | Onshore | 9,595 | | | 7,101 | | | 8,106 | | | 6,503 | |
| Offshore | 4,757 | | | 4,945 | | | 5,290 | | | 6,523 | |
Other | | — | | | 309 | | | 104 | | | 415 | |
Total net crude oil and condensate - continuing operations | 96,959 | | | 124,317 | | | 109,881 | | | 111,229 | |
Net natural gas liquids | | | | | | | |
United States | Onshore | 5,489 | | | 5,582 | | | 5,459 | | | 5,622 | |
| Gulf of Mexico 1 | 3,521 | | | 6,597 | | | 5,131 | | | 4,172 | |
Canada | Onshore | 1,513 | | | 1,422 | | | 1,311 | | | 1,197 | |
Total net natural gas liquids - continuing operations | 10,523 | | | 13,601 | | | 11,901 | | | 10,991 | |
Net natural gas – thousands of cubic feet per day | | | | | | | |
United States | Onshore | 27,520 | | | 29,122 | | | 29,054 | | | 30,203 | |
| Gulf of Mexico 1 | 53,046 | | | 72,897 | | | 67,850 | | | 44,029 | |
Canada | Onshore | 260,895 | | | 296,882 | | | 262,279 | | | 267,205 | |
Total net natural gas - continuing operations | 341,461 | | | 398,901 | | | 359,183 | | | 341,437 | |
Total net hydrocarbons - continuing operations including NCI 2,3 | 164,392 | | | 204,402 | | | 181,646 | | | 179,126 | |
Noncontrolling interest | | | | | | | | |
Net crude oil and condensate – barrels per day | (9,545) | | | (10,481) | | | (10,886) | | | (11,269) | |
Net natural gas liquids – barrels per day | (327) | | | (478) | | | (443) | | | (496) | |
Net natural gas – thousands of cubic feet per day 2 | (3,269) | | | (3,403) | | | (4,137) | | | (3,933) | |
Total noncontrolling interest | (10,417) | | | (11,526) | | | (12,019) | | | (12,421) | |
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 153,975 | | | 192,875 | | | 169,627 | | | 166,706 | |
| | | | | | | | |
Discontinued operations | | | | | | | | |
Net crude oil and condensate – barrels per day | — | | | 1,424 | | | — | | | 16,177 | |
Net natural gas liquids – barrels per day | — | | | 32 | | | — | | | 395 | |
Net natural gas – thousands of cubic feet per day 2 | — | | | 9,624 | | | — | | | 67,863 | |
Total discontinued operations | — | | | 3,060 | | | — | | | 27,883 | |
Total net hydrocarbons sold excluding NCI 2,3 | 153,975 | | | 195,935 | | | 169,627 | | | 194,588 | |
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 20202021 and 2019.2020. Comparative periods are conformed to current presentation.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 |
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 | $ | 37.83 | | | 58.80 | | | 35.56 | | | 60.33 | | United States | Onshore | 69.30 | | | 37.83 | | | 64.16 | | | 35.56 | |
| | Gulf of Mexico 1 | 40.82 | | | 60.69 | | | 38.08 | | | 61.90 | | | Gulf of Mexico 1 | 68.93 | | | 40.82 | | | 64.44 | | | 38.08 | |
Canada 2 | Canada 2 | Onshore | 36.65 | | | 48.61 | | | 30.29 | | | 49.98 | | Canada 2 | Onshore | 63.76 | | | 36.65 | | | 58.70 | | | 30.29 | |
| | Offshore | 43.81 | | | 62.44 | | | 37.85 | | | 64.97 | | | Offshore | 72.64 | | | 43.81 | | | 68.93 | | | 37.85 | |
Other | Other | | — | | | 67.96 | | | 63.51 | | | 69.86 | | Other | | — | | | — | | | — | | | 63.51 | |
Natural gas liquids – dollars per barrel | Natural gas liquids – dollars per barrel | | Natural gas liquids – dollars per barrel | |
United States | United States | Onshore | 13.39 | | | 10.82 | | | 10.78 | | | 14.66 | | United States | Onshore | 30.37 | | | 13.39 | | | 24.29 | | | 10.78 | |
| | Gulf of Mexico 1 | 14.71 | | | 13.86 | | | 9.43 | | | 15.96 | | | Gulf of Mexico 1 | 34.71 | | | 14.71 | | | 27.17 | | | 9.43 | |
Canada 2 | Canada 2 | Onshore | 19.97 | | | 21.03 | | | 16.95 | | | 27.50 | | Canada 2 | Onshore | 45.12 | | | 19.97 | | | 37.05 | | | 16.95 | |
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 | 1.78 | | | 2.18 | | | 1.76 | | | 2.51 | | United States | Onshore | 3.85 | | | 1.78 | | | 3.23 | | | 1.76 | |
| | Gulf of Mexico 1 | 2.01 | | | 2.37 | | | 1.91 | | | 2.46 | | | Gulf of Mexico 1 | 4.09 | | | 2.01 | | | 3.28 | | | 1.91 | |
Canada 2 | Canada 2 | Onshore | 1.74 | | | 1.16 | | | 1.62 | | | 1.50 | | Canada 2 | Onshore | 2.47 | | | 1.74 | | | 2.33 | | | 1.62 | |
Discontinued operations | | | |
Crude oil and condensate – dollars per barrel | | |
Malaysia 3 | Sarawak | — | | | — | | | — | | | 70.39 | | |
| | Block K | — | | | 69.24 | | | — | | | 65.75 | | |
Natural gas liquids – dollars per barrel | | |
Malaysia 3 | Sarawak | — | | | 54.11 | | | — | | | 48.23 | | |
Natural gas – dollars per thousand cubic feet | | |
Malaysia 3 | Sarawak | — | | | 3.69 | | | — | | | 3.60 | | |
| | Block K | — | | | 0.23 | | | — | | | 0.24 | | |
| | | | |
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3 Prices are net of payments under the terms of the respective production sharing contracts.
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $578.0$1,091.3 million for the first nine months of 20202021 compared to $1,153.2$578.0 million during the same period in 2019.2020. The decreasedincreased cash from operating activities is primarily attributable to lowerhigher revenue from sales to customers ($748.5727.3 million) and higher, lower working capital ($143.6 million), lower lease operating expensesexpense ($61.874.6 million), and lower general and administrative and cash restructuring expense ($47.4 million), partially offset by higher cash payments receivedmade on forward swap commodity contracts ($194.0(2021: realized loss of $271.3 million; 2020: realized gain of $215.0 million) and lower general and administrative expenses ($71.9 million). See above for explanation of underlying business reasons.
Cash Required by Investing Activities
CashNet cash required by propertyinvesting activities was $311.9 million for the first nine months of 2021 compared to $723.7 million during the same period in 2020. Property additions and dry holes,hole costs, which includes amounts expensed, were $723.7$582.0 million and $2,203.0$723.7 million in the nine-month periods ended September 30,first nine months of 2021 and 2020, and 2019, respectively. In 2020, property additionsThese amounts include $17.7 million and $74.9 million used to fund the development of the King’s Quay FPS in the first nine months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which is expected to be refunded onreimbursed the closing of a transaction to sell this asset to a third party. In 2019, property additions included the LLOG acquisition.Company for previously incurred capital expenditures. Lower property additions in 20202021 are a result ofprincipally 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.)
reducing the 2020 capital spending budget in response to the current commodity price environment. See Outlook section on page 35 for further details.
Total accrual basis capital expenditures were as follows:
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars) | (Millions of dollars) | 2020 | | 2019 | (Millions of dollars) | 2021 | | 2020 |
Capital Expenditures | Capital Expenditures | | | | Capital Expenditures | | | |
Exploration and production | Exploration and production | $ | 671.0 | | | 2,320.6 | | Exploration and production | $ | 556.0 | | | 671.0 | |
Corporate | Corporate | 9.3 | | | 8.5 | | Corporate | 12.7 | | | 9.3 | |
Total capital expenditures | Total capital expenditures | $ | 680.3 | | | 2,329.1 | | Total capital expenditures | $ | 568.7 | | | 680.3 | |
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Millions of dollars) | (Millions of dollars) | 2020 | | 2019 | (Millions of dollars) | 2021 | | 2020 |
Property additions and dry hole costs per cash flow statements | Property additions and dry hole costs per cash flow statements | $ | 648.7 | | | 995.5 | | Property additions and dry hole costs per cash flow statements | $ | 564.2 | | | 648.7 | |
Property additions King's Quay per cash flow statements | Property additions King's Quay per cash flow statements | 74.9 | | | 13.6 | | Property additions King's Quay per cash flow statements | 17.7 | | | 74.9 | |
Acquisition of oil and gas properties | — | | | 1,226.1 | | |
| Geophysical and other exploration expenses | Geophysical and other exploration expenses | 26.8 | | | 36.6 | | Geophysical and other exploration expenses | 13.3 | | | 26.8 | |
Capital expenditure accrual changes and other | Capital expenditure accrual changes and other | (70.2) | | | 57.1 | | Capital expenditure accrual changes and other | (26.6) | | | (70.2) | |
Total capital expenditures | Total capital expenditures | $ | 680.3 | | | 2,329.1 | | Total capital expenditures | $ | 568.7 | | | 680.3 | |
Capital expenditures in the exploration and production business in 20202021 compared to 20192020 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, with significant capital expenditure reductions in the Eagle Ford Shale. The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party.support generating positive free cash flow.
Cash Used in/ Provided by Financing Activities
Net cash providedrequired by financing activities was $59.1$585.6 million for the first nine months of 20202021 compared to net cash requiredprovided by financing activities of $961.4$59.1 million during the same period in 2019. 2020. In 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).
As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.
In 2020, the cash provided by financing activities was principally from net borrowings on the Company’s unsecured RCFrevolving credit facility ($200.0 million at450.0 million), offset by repayments on the end of the third quarter 2020). In 2019, the cash required by financing activities was principally from borrowings on our revolver and short-term loanrevolving credit facility ($1,575.0250.0 million) to fund the LLOG acquisition. These borrowings, along with the opening revolver balance ($325.0 million) of $1,900.0 million were repaid in July 2019 following the completion of the Malaysia divestment. Total, cash dividends to shareholders amounted($76.8 million), and distributions to $76.8 million for the nine months ended September 30, 2020 compared to $125.4 million in the same period of 2019 due to a 50% reduction in the quarterly dividend effective in the second quarter 2020 and cash used for share repurchases of $405.9 million throughout 2019. As of September 30, 2020 and in the event it is required to fund investing or operating activities from borrowings, the Company has $1,396.3 million available on its committed RCF.our noncontrolling interest ($43.7 million).
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 20202021 was $30.0a deficit of $344.9 million, $109.1$315.5 million higherlower than December 31, 2019,2020, with the increasedecrease primarily attributable to lowerhigher accounts payable $306.7 million and lower($208.3 million), higher other accrued liabilities $39.9 million,($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a lowerhigher cash balance ($87.1194.5 million) and lower accounts receivable ($147.575.3 million). LowerHigher accounts payable is primarily due to lower capital activity.the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS. Lower accounts receivable isare principally due to lower commodity sales prices.
Capital Employed
At September 30, 2020, long-term debtthe timing of $2,987.1 million had increased by $183.7 million comparedcash received from our joint venture partners to December 31, 2019, as a result of net borrowing on the RCF. The fixed-rate notes had a weighted average maturity of 7.0 years and a weighted average coupon of 5.9 percent.fund joint operations.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
Capital Employed
At September 30, 2021, long-term debt of $2,613.7 million had decreased by $374.4 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.
A summary of capital employed at September 30, 20202021 and December 31, 20192020 follows.
| | | September 30, 2020 | | December 31, 2019 | | September 30, 2021 | | December 31, 2020 |
(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 | $ | 2,987.1 | | | 40.7 | % | | $ | 2,803.4 | | | 33.9 | % | Long-term debt | $ | 2,613.7 | | | 39.8 | % | | $ | 2,988.1 | | | 41.5 | % |
Murphy shareholders' equity | Murphy shareholders' equity | 4,343.4 | | | 59.3 | % | | 5,467.5 | | | 66.1 | % | Murphy shareholders' equity | 3,949.5 | | | 60.2 | % | | 4,214.3 | | | 58.5 | % |
Total capital employed | Total capital employed | $ | 7,330.5 | | | 100.0 | % | | $ | 8,270.8 | | | 100.0 | % | Total capital employed | $ | 6,563.2 | | | 100.0 | % | | $ | 7,202.4 | | | 100.0 | % |
Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2020,2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $56.6$119.4 million in Canada. In addition, $18.4Canada and $6.2 million of cash was held in the United Kingdom and $11.0 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at September 30, 2020).Brunei. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements
Outlook
As discussed in the Summary section on page 23, average crude oil prices recoveredcontinued to recover during the third quartersecond half of 2021 versus 2020 from the low seen in the second quarter of 2020.(Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93). As of close on November 4, 2020,2, 2021, the NYMEX WTI forward curve pricesprice for the remainder of 20202021 and 20212022 were $39.15$83.91 and $41.06$76.27 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and other economic factorsOPEC+ decisions) may have on future commodity pricing. Lower prices, are expected toshould they occur, will result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between 146145.5 and 154153.5 MBOEPD, excluding NCI. If price volatility persists, the Company will review the option of production curtailmentsnoncontrolling interest (NCI).
The Company’s capital expenditure spend for 2021 is expected to avoid incurring losses on certain produced barrels.
In response to the COVID-19 pandemicbe between $675.0 million and reduced commodity prices, the Company reduced 2020$685.0 million. Capital and other expenditures are routinely reviewed and planned capital expenditures significantly frommay be adjusted to reflect differences between budgeted and forecast cash flow during the original plan of $1.4 billion to $1.5 billion toyear. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a range of $680 million to $720 million, excluding NCI. The Company has also embarked on a cost reduction plan for both future direct operational expenditures and general and administrative costs.budget is prepared. The Company will primarily fund its remaining capital program in 20202021 using operating cash flow but will supplement funding where necessary withand 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 available revolving credit facility. year to maintain funding of the Company’s ongoing development projects.
The Company is closely monitoringplans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt.
The Company continues to monitor the impact of lower commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company’s responseCompany continues to monitor the effects of the COVID-19 pandemic and is discussed in more detail inencouraged by the risk factors on page 38. progress of the vaccination roll-outs globally.
As of November 4, 2020,2, 2021, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
| | | 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 | | | $56.42 | | | 10/1/2020 | | 12/31/2020 | United States | | WTI ¹ | | Fixed price derivative swap | | 45,000 | | | $42.77 | | | 10/1/2021 | | 12/31/2021 |
United States | United States | | WTI ¹ | | Fixed price derivative swap | | 18,000 | | | $43.31 | | | 1/1/2021 | | 12/31/2021 | 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 | | WTI ¹ | | Derivative collars | | 23,000 | | | $62.652 | | | $74.774 | | | 1/1/2022 | | 12/31/2022 |
1 West Texas Intermediate
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Volumes (MMcf/d) | | Price (CAD/Mcf)Price/Mcf | | Remaining Period |
Area | | Commodity | | Type | | | | Start Date | | End Date |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 59196 | | | C$2.812.55 | | 10/1/2020 | | 12/31/2020 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 96 | | | C$2.53 | | 1/1/2021 | | 12/31/2021 |
Montney | | Natural Gas | | Fixed price forward sales at AECO | | 71186 | | | C$2.502.36 | | 1/1/2022 | | 1/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 176 | | | C$2.34 | | 2/1/2022 | | 4/30/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 205 | | | C$2.34 | | 5/1/2022 | | 5/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 247 | | | C$2.34 | | 6/1/2022 | | 10/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 266 | | | C$2.36 | | 11/1/2022 | | 12/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 269 | | | C$2.35 | | 1/1/2023 | | 3/31/2023 |
Montney | | Natural Gas | | Fixed price forward sales | | 250 | | | C$2.35 | | 4/1/2023 | | 12/31/2023 |
Montney | | Natural Gas | | Fixed price forward sales | | 162 | | | C$2.39 | | 1/1/2024 | | 12/31/2024 |
Montney | | Natural Gas | | Fixed price forward sales | | 45 | | | US$2.05 | | 10/1/2021 | | 12/31/2022 |
Montney | | Natural Gas | | Fixed price forward sales | | 25 | | | US$1.98 | | 1/1/2023 | | 10/31/2024 |
Montney | | Natural Gas | | Fixed price forward sales | | 15 | | | US$1.98 | | 11/1/2024 | | 12/31/2024 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Volumes (MMcf/d) | | Price (USD/MMBtu) | | Remaining Period |
Area | | Commodity | | Type | | | | Start Date | | End Date |
Montney | | Natural Gas | | Fixed price forward sales at Malin | | 20 | | | $2.60 | | | 1/1/2021 | | 12/31/2022 |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”“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 20192020 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 3837 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 September 30, 2020,2021, covering certain future U.S. crude oil sales volumes in 2020.2021 and 2022. A 10% increase in the respective benchmark price of these commodities would have decreasedincreased the net receivablepayable associated with these derivative contracts by approximately $44.7$113.6 million, while a 10% decrease would have increaseddecreased the recorded receivablenet payable by a similar amount.
There were no derivative foreign exchange contracts in place at September 30, 2020.2021.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended September 30, 2020,2021, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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 20192020 Form 10-K filed on February 27, 2020.26, 2021. The Company has not identified any additional risk factors not previously disclosed in its 20192020 Form 10-K report, except as discussed below.
Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.
Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil, natural gas liquids and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:
•the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;
•worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;
•the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;
•the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
•political instability or armed conflict in oil and natural gas producing regions;
•changes in weather patterns and climate;
•natural disasters such as hurricanes and tornadoes;
•the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
•the effect of conservation efforts;
•technological advances affecting energy consumption and energy supply;
•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
•general economic conditions worldwide.
The global downturn triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon (most notably oil) energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.
In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day (MMBLD) in May and June 2020. Production cuts of 9.6 MMBLD were extended through the end of July 2020 and cuts of 7.7 MMBLD were made for August and September. OPEC+ are expected to target cuts of 7.7 MMBLD for the remainder of 2020.
For the three months ended September 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $41 per barrel (compared to $46 and $28 and in the first and second quarters of 2020, respectively). The closing price for WTI at the end of the third quarter of 2020 was approximately $40 per barrel (compared to $30 per barrel at the end of the first quarter and $38 at the end of the second quarter), reflecting a 34% reduction from the price at the end of 2019. In comparison, WTI averaged approximately $57 in 2019, $65 in 2018 and $51 in 2017. The closing price for WTI at the end of 2019 was approximately $60 per barrel. As of close on November 4, 2020, the NYMEX WTI forward curve price for 2020 and 2021 were $39.15 and $41.06 per barrel, respectively. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the WTI prices.
The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended September 30, 2020 was $1.95 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of September 30, 2020, was $1.92 per MMBTU. In comparison, NYMEX natural gas was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017. The closing price for NYMEX natural gas as of December 31, 2019, was $2.19 per MMBTU. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged US$1.33 per MMBTU in 2019 and US$1.61 in 2020, up to the end of the third quarter. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 35 and certain variable netback contracts providing exposure to Malin and Chicago City Gate prices.
Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue for the remainder of 2020 and beyond. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize, which could impact the recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales.
See Note L - Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.
We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See “Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”
If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.
It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.
We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company has initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.
We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.
The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) its joint venture partners and (iii) other counterparties.
Murphy is exposed to credit risk in three principle areas:
•Accounts receivable credit risk from selling its produced commodity to customers;
•Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and
•Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices
To mitigate these risks the Company:
•Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;
•Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.
The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.report.
ITEM 6. EXHIBITS
The Exhibit Index on page 4239 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/ CHRISTOPHER D. HULSE |
| | Christopher D. Hulse |
| | Vice President and Controller |
| | (Chief Accounting Officer and Duly Authorized Officer) |
November 5, 20204, 2021
(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. | | | |
| | | |
| | |
| | |
| | |
| | |
| | |
| | |
101. INS | | XBRL Instance Document |
| | |
101. SCH | | XBRL Taxonomy Extension Schema Document |
| | |
101. CAL | | XBRL Taxonomy Extension Calculation Linkbase Document |
| | |
101. DEF | | XBRL Taxonomy Extension Definition Linkbase Document |
| | |
101. LAB | | XBRL Taxonomy Extension Labels Linkbase Document |
| | |
101. PRE | | XBRL Taxonomy Extension Presentation Linkbase | |
Exhibits other than those listed above have been omitted since they are either not required or not applicable.