MURPHY OIL CORP - Quarter Report: 2023 June (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) | |||||
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the quarterly period ended June 30, 2023
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from to
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 71-0361522 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |||||||
| 9805 Katy Fwy, Suite G-200 | 77024 | |||||||
| Houston, | Texas | (Zip Code) | ||||||
| (Address of principal executive offices) | ||||||||
| (281) | 675-9000 | |||||||
| (Registrant’s telephone number, including area code) | ||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
| Common Stock, $1.00 Par Value | MUR | New York Stock Exchange | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.
| Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐ | ||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2023 was 156,155,341.
MURPHY OIL CORPORATION
TABLE OF CONTENTS
| Page | |||||
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| (Thousands of dollars, except share amounts) | June 30, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 369,355 | $ | 491,963 | |||||||
Accounts receivable, net | 409,989 | 391,152 | |||||||||
| Inventories | 62,450 | 54,513 | |||||||||
| Prepaid expenses | 27,354 | 34,697 | |||||||||
| Total current assets | 869,148 | 972,325 | |||||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,984,567 in 2023 and $12,489,970 in 2022 | 8,426,045 | 8,228,016 | |||||||||
| Operating lease assets | 867,353 | 946,406 | |||||||||
| Deferred income taxes | 40,678 | 117,889 | |||||||||
| Deferred charges and other assets | 46,306 | 44,316 | |||||||||
| Total assets | $ | 10,249,530 | $ | 10,308,952 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 705 | $ | 687 | |||||||
| Accounts payable | 584,107 | 543,786 | |||||||||
| Income taxes payable | 23,539 | 26,544 | |||||||||
| Other taxes payable | 32,091 | 22,819 | |||||||||
| Operating lease liabilities | 258,278 | 220,413 | |||||||||
| Other accrued liabilities | 135,788 | 443,585 | |||||||||
| Total current liabilities | 1,034,508 | 1,257,834 | |||||||||
| Long-term debt, including finance lease obligation | 1,823,521 | 1,822,452 | |||||||||
| Asset retirement obligations | 843,328 | 817,268 | |||||||||
| Deferred credits and other liabilities | 299,089 | 304,948 | |||||||||
| Non-current operating lease liabilities | 624,736 | 742,654 | |||||||||
| Deferred income taxes | 235,665 | 214,903 | |||||||||
| Total liabilities | $ | 4,860,847 | $ | 5,160,059 | |||||||
| Equity | |||||||||||
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | $ | – | $ | – | |||||||
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2023 and 195,100,628 shares in 2022 | 195,101 | 195,101 | |||||||||
| Capital in excess of par value | 861,951 | 893,578 | |||||||||
| Retained earnings | 6,259,561 | 6,055,498 | |||||||||
| Accumulated other comprehensive loss | (495,783) | (534,686) | |||||||||
| Treasury stock | (1,586,522) | (1,614,717) | |||||||||
| Murphy Shareholders' Equity | 5,234,308 | 4,994,774 | |||||||||
| Noncontrolling interest | 154,375 | 154,119 | |||||||||
| Total equity | 5,388,683 | 5,148,893 | |||||||||
| Total liabilities and equity | $ | 10,249,530 | $ | 10,308,952 | |||||||
2
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | 799,836 | $ | 1,146,299 | $ | 1,596,067 | $ | 1,980,827 | |||||||||||||||
| Sales of purchased natural gas | 13,014 | 49,939 | 56,751 | 86,785 | |||||||||||||||||||
| Total revenue from sales to customers | 812,850 | 1,196,238 | 1,652,818 | 2,067,612 | |||||||||||||||||||
| Loss on derivative instruments | – | (103,068) | – | (423,845) | |||||||||||||||||||
| Gain on sale of assets and other income | 1,738 | 7,887 | 3,486 | 10,251 | |||||||||||||||||||
| Total revenues and other income | 814,588 | 1,101,057 | 1,656,304 | 1,654,018 | |||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 194,292 | 147,352 | 394,276 | 284,177 | |||||||||||||||||||
| Severance and ad valorem taxes | 12,765 | 17,565 | 24,205 | 32,200 | |||||||||||||||||||
| Transportation, gathering and processing | 59,868 | 49,948 | 113,790 | 96,871 | |||||||||||||||||||
| Costs of purchased natural gas | 9,657 | 47,971 | 41,926 | 81,636 | |||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | 115,793 | 15,151 | 125,975 | 62,717 | |||||||||||||||||||
| Selling and general expenses | 25,345 | 27,130 | 43,653 | 60,659 | |||||||||||||||||||
| Depreciation, depletion and amortization | 215,667 | 195,856 | 411,337 | 359,980 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,364 | 11,563 | 22,521 | 23,439 | |||||||||||||||||||
| Other operating expense | 4,960 | 36,913 | 16,948 | 142,855 | |||||||||||||||||||
| Total costs and expenses | 649,711 | 549,449 | 1,194,631 | 1,144,534 | |||||||||||||||||||
| Operating income from continuing operations | 164,877 | 551,608 | 461,673 | 509,484 | |||||||||||||||||||
| Other income (loss) | |||||||||||||||||||||||
| Other (expenses) income | (7,694) | 5,308 | (7,767) | 2,813 | |||||||||||||||||||
| Interest expense, net | (29,856) | (41,385) | (58,711) | (78,662) | |||||||||||||||||||
| Total other loss | (37,550) | (36,077) | (66,478) | (75,849) | |||||||||||||||||||
| Income from continuing operations before income taxes | 127,327 | 515,531 | 395,195 | 433,635 | |||||||||||||||||||
| Income tax expense | 34,870 | 105,084 | 88,703 | 88,123 | |||||||||||||||||||
| Income from continuing operations | 92,457 | 410,447 | 306,492 | 345,512 | |||||||||||||||||||
| Loss from discontinued operations, net of income taxes | (602) | (943) | (323) | (1,494) | |||||||||||||||||||
| Net income including noncontrolling interest | 91,855 | 409,504 | 306,169 | 344,018 | |||||||||||||||||||
| Less: Net (loss) income attributable to noncontrolling interest | (6,431) | 58,947 | 16,239 | 106,797 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | 98,286 | $ | 350,557 | $ | 289,930 | $ | 237,221 | |||||||||||||||
| INCOME PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | 0.63 | 2.27 | $ | 1.86 | $ | 1.54 | ||||||||||||||||
| Discontinued operations | – | (0.01) | – | (0.01) | |||||||||||||||||||
| Net income | $ | 0.63 | 2.26 | $ | 1.86 | $ | 1.53 | ||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | 0.62 | $ | 2.24 | $ | 1.84 | $ | 1.51 | |||||||||||||||
| Discontinued operations | – | (0.01) | – | (0.01) | |||||||||||||||||||
| Net income | $ | 0.62 | $ | 2.23 | $ | 1.84 | $ | 1.50 | |||||||||||||||
| Cash dividends per common share | $ | 0.275 | $ | 0.175 | $ | 0.550 | $ | 0.325 | |||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | 156,127 | 155,389 | 155,976 | 155,121 | |||||||||||||||||||
| Diluted | 157,299 | 157,455 | 157,308 | 157,852 | |||||||||||||||||||
3
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income including noncontrolling interest | $ | 91,855 | $ | 409,504 | $ | 306,169 | $ | 344,018 | |||||||||||||||
| Other comprehensive (loss) income, net of tax | |||||||||||||||||||||||
| Net gain (loss) from foreign currency translation | 33,083 | (51,545) | 36,752 | (33,525) | |||||||||||||||||||
| Retirement and postretirement benefit plans | 1,053 | 3,173 | 2,151 | 6,509 | |||||||||||||||||||
| Other comprehensive (loss) income | 34,136 | (48,372) | 38,903 | (27,016) | |||||||||||||||||||
| Comprehensive income (loss) including noncontrolling interest | $ | 125,991 | $ | 361,132 | $ | 345,072 | $ | 317,002 | |||||||||||||||
| Less: Comprehensive income attributable to noncontrolling interest | (6,431) | 58,947 | 16,239 | 106,797 | |||||||||||||||||||
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 132,422 | $ | 302,185 | $ | 328,833 | $ | 210,205 | |||||||||||||||
4
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2023 | 2022 | |||||||||
| Operating Activities | |||||||||||
| Net income including noncontrolling interest | $ | 306,169 | $ | 344,018 | |||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||
| Loss from discontinued operations | 323 | 1,494 | |||||||||
| Depreciation, depletion and amortization | 411,337 | 359,980 | |||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 96,533 | 34,102 | |||||||||
| Amortization of undeveloped leases | 5,369 | 7,980 | |||||||||
| Accretion of asset retirement obligations | 22,521 | 23,439 | |||||||||
| Deferred income tax expense | 92,557 | 66,691 | |||||||||
| Contingent consideration payment | (139,574) | – | |||||||||
| Mark to market loss on contingent consideration | 7,113 | 129,818 | |||||||||
| Mark to market loss on derivative instruments | – | 100,343 | |||||||||
| Long-term non-cash compensation | 22,076 | 40,467 | |||||||||
| Gain from sale of assets | – | (35) | |||||||||
| Net increase in noncash working capital | (15,340) | (121,598) | |||||||||
| Other operating activities, net | (59,417) | (27,458) | |||||||||
| Net cash provided by continuing operations activities | 749,667 | 959,241 | |||||||||
| Investing Activities | |||||||||||
| Property additions and dry hole costs | (694,753) | (552,825) | |||||||||
| Acquisition of oil and natural gas properties | – | (46,491) | |||||||||
| Proceeds from sales of property, plant and equipment | – | 47 | |||||||||
| Net cash required by investing activities | (694,753) | (599,269) | |||||||||
| Financing Activities | |||||||||||
| Borrowings on revolving credit facility | 200,000 | 100,000 | |||||||||
| Repayment of revolving credit facility | (200,000) | (100,000) | |||||||||
| Retirement of debt | – | (200,000) | |||||||||
| Early redemption of debt cost | – | (3,438) | |||||||||
| Distributions to noncontrolling interest | (15,983) | (94,854) | |||||||||
| Contingent consideration payment | (60,243) | (81,742) | |||||||||
| Cash dividends paid | (85,867) | (50,491) | |||||||||
| Withholding tax on stock-based incentive awards | (14,220) | (16,697) | |||||||||
| Capital lease obligation payments | (296) | (320) | |||||||||
| Issue costs of debt facility | (20) | – | |||||||||
| Net cash required by financing activities | (176,629) | (447,542) | |||||||||
| Effect of exchange rate changes on cash and cash equivalents | (893) | (1,595) | |||||||||
| Net decrease in cash and cash equivalents | (122,608) | (89,165) | |||||||||
| Cash and cash equivalents at beginning of period | 491,963 | 521,184 | |||||||||
| Cash and cash equivalents at end of period | $ | 369,355 | $ | 432,019 | |||||||
5
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars except number of shares) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued | $ | – | $ | – | $ | – | $ | – | |||||||||||||||
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2023 and 195,100,628 shares at June 30, 2022 | |||||||||||||||||||||||
| Balance at beginning and end of period | 195,101 | 195,101 | 195,101 | 195,101 | |||||||||||||||||||
| Capital in Excess of Par Value | |||||||||||||||||||||||
| Balance at beginning of period | 857,000 | 880,537 | 893,578 | 926,698 | |||||||||||||||||||
| Restricted stock transactions and other | (2,321) | (3,415) | (42,415) | (55,804) | |||||||||||||||||||
| Share-based compensation | 7,272 | 6,246 | 10,788 | 12,474 | |||||||||||||||||||
| Balance at end of period | 861,951 | 883,368 | 861,951 | 883,368 | |||||||||||||||||||
| Retained Earnings | |||||||||||||||||||||||
| Balance at beginning of period | 6,204,217 | 5,082,034 | 6,055,498 | 5,218,670 | |||||||||||||||||||
| Net income attributable to Murphy | 98,286 | 350,557 | 289,930 | 237,221 | |||||||||||||||||||
| Cash dividends paid | (42,942) | (27,191) | (85,867) | (50,491) | |||||||||||||||||||
| Balance at end of period | 6,259,561 | 5,405,400 | 6,259,561 | 5,405,400 | |||||||||||||||||||
| Accumulated Other Comprehensive Loss | |||||||||||||||||||||||
| Balance at beginning of period | (529,919) | (506,355) | (534,686) | (527,711) | |||||||||||||||||||
| Foreign currency translation (loss) gain, net of income taxes | 33,083 | (51,545) | 36,752 | (33,525) | |||||||||||||||||||
| Retirement and postretirement benefit plans, net of income taxes | 1,053 | 3,173 | 2,151 | 6,509 | |||||||||||||||||||
| Balance at end of period | (495,783) | (554,727) | (495,783) | (554,727) | |||||||||||||||||||
| Treasury Stock | |||||||||||||||||||||||
| Balance at beginning of period | (1,588,841) | (1,618,478) | (1,614,717) | (1,655,447) | |||||||||||||||||||
| Awarded restricted stock, net of forfeitures | 2,319 | 2,138 | 28,195 | 39,107 | |||||||||||||||||||
Balance at end of period – 38,945,622 shares of Common Stock in 2023 and 39,677,584 shares of Common Stock in 2022, at cost | (1,586,522) | (1,616,340) | (1,586,522) | (1,616,340) | |||||||||||||||||||
| Murphy Shareholders’ Equity | 5,234,308 | 4,312,802 | 5,234,308 | 4,312,802 | |||||||||||||||||||
| Noncontrolling Interest | |||||||||||||||||||||||
| Balance at beginning of period | 167,110 | 171,451 | 154,119 | 163,485 | |||||||||||||||||||
| Net income attributable to noncontrolling interest | (6,431) | 58,947 | 16,239 | 106,797 | |||||||||||||||||||
| Distributions to noncontrolling interest owners | (6,304) | (54,970) | (15,983) | (94,854) | |||||||||||||||||||
| Balance at end of period | 154,375 | 175,428 | 154,375 | 175,428 | |||||||||||||||||||
| Total Equity | $ | 5,388,683 | $ | 4,488,230 | $ | 5,388,683 | $ | 4,488,230 | |||||||||||||||
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas exploration and production company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States (U.S.) and Canada and conducts oil and natural gas exploration activities worldwide.
In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG) acquisition, we hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated as Murphy is not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2023, our maximum exposure to loss was $3.1 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2023 and December 31, 2022, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2023 and 2022, in conformity with U.S generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2022 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 2023 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
None.
Recent Accounting Pronouncements
None affecting the Company.
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and natural gas production where the non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
this is the reporting of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM) as prescribed by ASC 810-10-45.
U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load, based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-month periods ended June 30, 2023, and 2022, the Company recognized $812.9 million and $1,196.2 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.
For the six-month periods ended June 30, 2023, and 2022, the Company recognized $1,652.8 million and $2,067.6 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Net crude oil and condensate revenue | ||||||||||||||||||||||||||
United States | Onshore | $ | 177,085 | $ | 264,841 | $ | 307,166 | $ | 436,537 | |||||||||||||||||
| Offshore | 480,841 | 612,526 | 981,151 | 1,078,147 | ||||||||||||||||||||||
Canada | Onshore | 19,306 | 40,417 | 41,258 | 77,114 | |||||||||||||||||||||
| Offshore | 24,871 | 38,354 | 41,001 | 67,186 | ||||||||||||||||||||||
Other | – | 13,636 | 3,644 | 13,636 | ||||||||||||||||||||||
| Total crude oil and condensate revenue | 702,103 | 969,774 | 1,374,220 | 1,672,620 | ||||||||||||||||||||||
| Net natural gas liquids revenue | ||||||||||||||||||||||||||
United States | Onshore | 6,540 | 18,062 | 14,810 | 34,747 | |||||||||||||||||||||
| Offshore | 11,541 | 18,093 | 26,170 | 32,072 | ||||||||||||||||||||||
Canada | Onshore | 1,517 | 5,001 | 4,980 | 9,868 | |||||||||||||||||||||
| Total natural gas liquids revenue | 19,598 | 41,156 | 45,960 | 76,687 | ||||||||||||||||||||||
| Net natural gas revenue | ||||||||||||||||||||||||||
United States | Onshore | 4,138 | 19,034 | 9,588 | 30,403 | |||||||||||||||||||||
| Offshore | 14,802 | 43,567 | 36,934 | 69,768 | ||||||||||||||||||||||
Canada | Onshore | 59,195 | 72,768 | 129,365 | 131,349 | |||||||||||||||||||||
| Total natural gas revenue | 78,135 | 135,369 | 175,887 | 231,520 | ||||||||||||||||||||||
| Revenue from production | 799,836 | 1,146,299 | 1,596,067 | 1,980,827 | ||||||||||||||||||||||
| Sales of purchased natural gas | ||||||||||||||||||||||||||
United States | Offshore | – | 181 | – | 181 | |||||||||||||||||||||
Canada | Onshore | 13,014 | 49,758 | 56,751 | 86,604 | |||||||||||||||||||||
| Total sales of purchased natural gas | 13,014 | 49,939 | 56,751 | 86,785 | ||||||||||||||||||||||
| Total revenue from sales to customers | 812,850 | 1,196,238 | 1,652,818 | 2,067,612 | ||||||||||||||||||||||
| Loss on derivative instruments | – | (103,068) | – | (423,845) | ||||||||||||||||||||||
| Gain on sale of assets and other income | 1,738 | 7,887 | 3,486 | 10,251 | ||||||||||||||||||||||
| Total revenues and other income | $ | 814,588 | $ | 1,101,057 | $ | 1,656,304 | $ | 1,654,018 | ||||||||||||||||||
Contract Balances and Asset Recognition
As of June 30, 2023, and December 31, 2022, receivables from contracts with customers, net of royalties and associated payables, on the balance sheets from continuing operations, were $197.4 million and $201.1 million,
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any revenue contracts that have financing components as of June 30, 2023.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.
As of June 30, 2023, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:
| Current Long-Term Contracts Outstanding at June 30, 2023 | ||||||||||||||||||||||||||
| Location | Commodity | End Date | Description | Approximate Volumes | ||||||||||||||||||||||
| U.S. | Natural Gas and NGL | Q1 2030 | Deliveries from dedicated acreage in Eagle Ford | As produced | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2023 | Contracts to sell natural gas at USD index pricing | 25 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2023 | Contracts to sell natural gas at CAD fixed prices | 38 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at USD index pricing | 31 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at CAD fixed prices | 100 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at CAD fixed prices | 34 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at USD index fixed prices | 15 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at CAD index prices | 28 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2026 | Contracts to sell natural gas at USD index pricing | 49 MMCFD | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2027 | Contracts to sell natural gas at CAD index prices | 10 MMCFD | ||||||||||||||||||||||
| Canada | NGL | Q3 2023 | Contracts to sell natural gas liquids at CAD prices | 952 BOEPD | ||||||||||||||||||||||
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant and Equipment
Exploratory Wells
Under Financial Accounting Standards Board 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.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
As of June 30, 2023, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $193.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2023 and 2022.
| (Thousands of dollars) | 2023 | 2022 | |||||||||
| Beginning balance at January 1 | $ | 171,860 | $ | 179,481 | |||||||
| Additions pending the determination of proved reserves | 47,733 | 9,412 | |||||||||
| Capitalized exploratory well costs charged to expense | (26,188) | (10,472) | |||||||||
| Balance at June 30 | $ | 193,405 | $ | 178,421 | |||||||
Capital additions of $47.7 million in 2023 are primarily related to Oso #1 well (Atwater Valley 138) and Longclaw GC 433 #1 in the Gulf of Mexico and LDV-4X in Vietnam. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the third quarter of 2023. Capitalized well costs charged to dry hole expense of $26.2 million for the six months ended June 30, 2023 are related to Cholula -1 EXP well in Mexico and Chinook #7 exploration well in the Gulf of Mexico. The preceding table excludes well costs of $70.3 million incurred and expensed directly to dry hole during the six months ended June 30, 2023, related to the Chinook #7 exploration well in the Gulf of Mexico.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
| June 30, | |||||||||||||||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Amount | No. of Wells | No. of Projects | Amount | No. of Wells | No. of Projects | |||||||||||||||||||||||||||||
| Aging of capitalized well costs: | |||||||||||||||||||||||||||||||||||
| Zero to one year | $ | 8,494 | 1 | 1 | $ | 4,268 | 2 | 2 | |||||||||||||||||||||||||||
| One to two years | 38,497 | 1 | 1 | 2,813 | 2 | 2 | |||||||||||||||||||||||||||||
| Two to three years | 2,698 | 1 | 1 | 26,848 | 3 | 2 | |||||||||||||||||||||||||||||
| Three years or more | 143,716 | 4 | 3 | 144,492 | 8 | 2 | |||||||||||||||||||||||||||||
| $ | 193,405 | 7 | 6 | $ | 178,421 | 15 | 8 | ||||||||||||||||||||||||||||
Of the $184.9 million of exploratory well costs capitalized more than one year at June 30, 2023, $112.4 million was in Vietnam, $65.0 million was in the U.S., $4.8 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Impairments
There were no impairments in the six months ended June 30, 2023 or 2022.
Divestitures
On July 31, 2023 the Company entered into a purchase and sale agreement to sell a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash consideration of C$150 million. The transaction is anticipated to close in the third quarter of 2023, subject to closing conditions and adjustments. No gain or loss is anticipated in relation to this transaction. These assets did not meet the accounting criteria to be disclosed as held for sale as of June 30, 2023 and continue to be classified as “Property, plant and equipment” on the Company’s Consolidated Balance Sheets.
Note E – Financing Arrangements and Debt
As of June 30, 2023, the Company had an $800 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on November 17, 2027, unless the outstanding principal amount of the Company’s 5.75% senior notes due 2025 (2025 Notes) as at February 15, 2025 exceeds $50.0 million, in
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note E – Financing Arrangements and Debt (Continued)
which case, the RCF will expire on that date. As of June 30, 2023, the Company had $248.7 million outstanding on the 2025 Notes. At June 30, 2023, the Company had no outstanding borrowings under the RCF and $30.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2023, the interest rate in effect on borrowings under the RCF would have been 7.74%. At June 30, 2023, the Company was in compliance with all covenants related to the RCF.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2024.
Note F – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2023 | 2022 | |||||||||
| Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | |||||||||||
| (Increase) in accounts receivable | $ | (18,915) | $ | (263,104) | |||||||
| (Increase) decrease in inventories | (8,353) | (10,092) | |||||||||
| (Increase) decrease in prepaid expenses | 8,291 | (1,693) | |||||||||
| Increase in accounts payable and accrued liabilities ¹ | 6,642 | 147,790 | |||||||||
| Increase (decrease) in income taxes payable | (3,005) | 5,501 | |||||||||
| Net increase in noncash working capital | $ | (15,340) | $ | (121,598) | |||||||
| Supplementary disclosures: | |||||||||||
| Cash income taxes paid, net of refunds | $ | 10,904 | $ | 1,783 | |||||||
Interest paid, net of amounts capitalized of $6.8 million in 2023 and $10.4 million in 2022 | 54,305 | 78,747 | |||||||||
| Non-cash investing activities: | |||||||||||
| Asset retirement costs capitalized | $ | 2,742 | $ | 9,007 | |||||||
| (Increase) decrease in capital expenditure accrual | 20,522 | (1,929) | |||||||||
1 Excludes payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.
Note G – Asset Retirement Obligations
The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.
A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the six-month periods ended June 30, 2023 and 2022 is shown in the following table.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note G – Asset Retirement Obligations (Continued)
| (Thousands of dollars) | June 30, 2023 | June 30, 2022 | |||||||||
| Balance at beginning of year | $ | 911,653 | 971,893 | ||||||||
| Accretion | 22,521 | 23,439 | |||||||||
| Liabilities incurred | 4,805 | 9,007 | |||||||||
| Revisions of previous estimates | (822) | — | |||||||||
| Liabilities settled | (64,978) | (26,144) | |||||||||
| Changes due to translation of foreign currencies | 2,920 | (3,650) | |||||||||
| Balance at end of year | 876,099 | 974,545 | |||||||||
| Current portion of liability at June 30 ¹ | (32,771) | (110,653) | |||||||||
| Noncurrent portion of liability at June 30 | $ | 843,328 | 863,892 | ||||||||
1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.
The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.
Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans meet the requirements of 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.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2023 and 2022.
| Three Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Service cost | $ | 1,650 | $ | 2,129 | $ | 132 | $ | 292 | |||||||||||||||
| Interest cost | 8,564 | 5,139 | 874 | 574 | |||||||||||||||||||
| Expected return on plan assets | (8,254) | (7,954) | – | – | |||||||||||||||||||
| Estimated defined contribution provision | 54 | – | – | – | |||||||||||||||||||
| Amortization of prior service cost (credit) | 155 | 579 | (133) | (133) | |||||||||||||||||||
| Recognized actuarial loss (gain) | 2,414 | 3,822 | (767) | (78) | |||||||||||||||||||
| Total net periodic benefit expense | $ | 4,583 | 3,715 | 106 | 655 | ||||||||||||||||||
| Six Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Service cost | $ | 3,300 | $ | 4,258 | $ | 264 | $ | 584 | |||||||||||||||
| Interest cost | 17,071 | 10,382 | 1,748 | 1,148 | |||||||||||||||||||
| Expected return on plan assets | (16,448) | (16,092) | – | – | |||||||||||||||||||
| Estimated defined contribution provision | 108 | — | – | – | |||||||||||||||||||
| Amortization of prior service cost (credit) | 310 | 1,179 | (266) | (266) | |||||||||||||||||||
| Recognized actuarial loss (gain) | 4,815 | 7,644 | (1,548) | (155) | |||||||||||||||||||
| Total net periodic benefit expense | $ | 9,156 | $ | 7,371 | $ | 198 | $ | 1,311 | |||||||||||||||
The components of net periodic benefit expense, other than the service cost, are recorded in “Other (expenses) income” in the Consolidated Statements of Operations.
During the six-month period ended June 30, 2023, the Company made contributions of $18.9 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2023 for the Company’s defined benefit pension and postretirement plans is anticipated to be $18.2 million.
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of five million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.
During the six months ended June 30, 2023, 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 | 409,160 | January 31, 2023 | $ | 60.46 | Monte Carlo | |||||||||||||||||||||
Time Based RSUs 2 | 499,220 | January 31, 2023 | 43.27 | Average Stock Price | ||||||||||||||||||||||
Cash Settled RSUs 3 | 123,230 | January 31, 2023 | 43.27 | Average Stock Price | ||||||||||||||||||||||
1 Performance based RSUs are scheduled to vest over a three year performance period.
2 Time based RSUs are generally scheduled to vest over three years from the date of grant.
3 Cash settled RSUs are generally scheduled to vest over three years from the date of grant.
The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan) and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.
During the six months ended June 30, 2023, the Committee granted the following awards to Non-Employee Directors:
2021 Stock Plan for Non-Employee Directors
| Type of Award | Number of Awards Granted | Grant Date | Grant Date Fair Value | Valuation Methodology | ||||||||||||||||||||||
Time Based RSUs 1 | 56,880 | February 1, 2023 | $ | 42.20 | Closing Stock Price | |||||||||||||||||||||
1 Non-employee directors time-based RSUs are scheduled to vest in February 2024.
All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the six-month period ended June 30, 2023.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2023 | 2022 | |||||||||
| Compensation charged against income before tax benefit | $ | 23,684 | $ | 34,016 | |||||||
| Related income tax benefit recognized in income | 3,444 | 5,822 | |||||||||
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note J – Earnings Per Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2023 and 2022. The following table reports the weighted-average shares outstanding used for these computations.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Weighted-average shares) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Basic method | 156,126,580 | 155,388,555 | 155,976,326 | 155,121,098 | |||||||||||||||||||
| Dilutive stock options and restricted stock units ¹ | 1,172,382 | 2,066,575 | 1,331,696 | 2,730,624 | |||||||||||||||||||
| Diluted method | 157,298,962 | 157,455,130 | 157,308,022 | 157,851,722 | |||||||||||||||||||
1 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.
| Six Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
| Antidilutive stock options excluded from diluted shares | $ | – | $ | 234,000 | |||||||
| Weighted average price of these options | $ | – | $ | 49.65 | |||||||
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and six-month periods ended June 30, 2023 and 2022, the Company’s effective income tax rates were as follows:
| 2023 | 2022 | ||||||||||
| Three months ended June 30, | 27.4% | 20.4% | |||||||||
| Six months ended June 30, | 22.4% | 20.3% | |||||||||
The effective tax rate for the three-month period ended June 30, 2023, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: no tax benefit applied to the pre-tax loss of the noncontrolling interest in MP GOM; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.
The effective tax rate for the three-month period ended June 30, 2022, was below the statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the six-month period ended June 30, 2023 was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The effective tax rate for the six-month period ended June 30, 2022 was below the statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM offset by exploration expenses in certain foreign jurisdictions in which no income tax benefit is currently available.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company has paid amounts into escrow, and may from time to time pay more amounts
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note K – Income Taxes (Continued)
into escrow, in order to continue tax disputes with the relevant taxing authorities. As of June 30, 2023, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2016. Following the sale in 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.
Commodity Price Risks
During the second quarter of 2023, the Company did not have any outstanding crude oil derivative contracts.
During the second quarter of 2022, the Company had crude oil swaps and collar contracts. Under the swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received 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 matured 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 required payments by the Company if the NYMEX average closing price was above the ceiling price or payments to the Company if the NYMEX average closing price was below the floor price.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at June 30, 2023 and 2022.
For the three-month and six-month periods ended June 30, 2023 and 2022, 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) | Statements of Operations Location | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
| Type of Derivative Contract | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||
| Commodity swaps | Loss on derivative instruments | $ | – | $ | (46,552) | $ | – | $ | (202,911) | |||||||||||||||||||||||
| Commodity collars | Loss on derivative instruments | – | (56,516) | – | (220,934) | |||||||||||||||||||||||||||
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
The carrying value of assets and liabilities recorded at fair value on a recurring basis at June 30, 2023 and December 31, 2022, are presented in the following table.
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Nonqualified employee savings plan | $ | 15,273 | $ | – | $ | – | $ | 15,273 | $ | 15,135 | $ | – | $ | – | $ | 15,135 | ||||||||||||||||||||||||||||||||||
| $ | 15,273 | $ | – | $ | – | $ | 15,273 | $ | 15,135 | $ | – | $ | – | $ | 15,135 | |||||||||||||||||||||||||||||||||||
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.
As of June 30, 2023, there were no outstanding commodity West Texas Intermediate (WTI) crude oil swaps and collars contracts subject to fair value measurement.
As of December 31, 2022, there were no outstanding commodity (WTI crude oil) swaps and collars contracts subject to fair value measurement. The liabilities associated with these contracts have been finalized as of December 31, 2022 and were based on realized WTI pricing. The commodity swaps and collars liability as of December 31, 2022 was $19.6 million and $2.3 million, respectively, and recorded as “Accounts payable” in the Consolidated Balance Sheets.
In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG). Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds were exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020; however, the threshold was met in 2021 and 2022. The obligation period related to LLOG revenue-related contingent consideration ended in 2022, with final payments made in the first half of 2023.
In 2018, the Company, through a subsidiary, acquired Gulf of Mexico producing assets from Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A. Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $150 million if certain price and production thresholds were exceeded beginning in 2019 through 2025; and $50 million carry for PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. The price and production thresholds were not exceeded for 2019 and 2020; however, the thresholds were met in 2021 and 2022. As of December 31, 2021, Murphy had completely funded the carried interest. As of December 31, 2022, the $150 million obligation limit was achieved and paid in the first half of 2023.
As at June 30, 2023, the Company had no remaining liabilities relating to prior acquisitions from PAI and LLOG. As at December 31, 2022, the Company’s liabilities with PAI and LLOG were based on realized inputs of volumes and pricing as a result of reaching contractual thresholds or time limitations that ended in 2022. As a result, the related liabilities as at December 31, 2022 of $192.7 million were no longer subject to fair value measurement. The liability remaining was included in “Other accrued liabilities” in the Consolidated Balance Sheets. During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration payments, thereby reducing the liability balance to nil as at June 30, 2023. In the Consolidated Statement of Cash Flows, $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities”.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at June 30, 2023 and December 31, 2022.
The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at June 30, 2023 and December 31, 2022. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. The Company has
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.
| June 30, | December 31, | ||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| (Thousands of dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||
Financial liabilities: | |||||||||||||||||||||||
| Current and long-term debt | $ | 1,824,226 | $ | 1,728,376 | $ | 1,823,139 | $ | 1,668,216 | |||||||||||||||
Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2022 and June 30, 2023 and the changes during the six-month period ended June 30, 2023 are presented net of taxes in the following table.
| (Thousands of dollars) | Foreign Currency Translation Gains (Losses) | Retirement and Postretirement Benefit Plan Adjustments | Total | ||||||||||||||
| Balance at December 31, 2022 | $ | (418,230) | $ | (116,456) | $ | (534,686) | |||||||||||
| Components of other comprehensive income (loss): | |||||||||||||||||
| Before reclassifications to income | 36,752 | – | 36,752 | ||||||||||||||
| Reclassifications to income ¹ | – | 2,151 | 2,151 | ||||||||||||||
| Net other comprehensive income (loss) | 36,752 | 2,151 | 38,903 | ||||||||||||||
| Balance at June 30, 2023 | $ | (381,478) | $ | (114,305) | $ | (495,783) | |||||||||||
1 Reclassifications before taxes of $2,669 thousand are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2023. See Note H for additional information. Related income taxes of $518 thousand are included in “Income tax expense (benefit)” on the Consolidated Statements of Operations for the six-month period ended June 30, 2023.
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.
ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including Greenhouse Gas (GHG) emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.
Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, 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 this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environment legal proceedings likely to exceed this $1.0 million threshold.
There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, the Inflation Reduction Act of 2022 contains provisions that impose fees for excess methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)
prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
21
Note O – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on commodity price derivatives), interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.) and U.S. refining and marketing operations as discontinued operations for all periods presented.
| Total Assets at June 30, 2023 | Three Months Ended June 30, 2023 | Three Months Ended June 30, 2022 | ||||||||||||||||||||||||||||||
| (Millions of dollars) | External Revenues | Income (Loss) | External Revenues | Income (Loss) | ||||||||||||||||||||||||||||
| Exploration and production ¹ | ||||||||||||||||||||||||||||||||
| United States | $ | 6,963.3 | $ | 696.2 | 168.9 | $ | 978.0 | 491.5 | ||||||||||||||||||||||||
| Canada | 2,234.7 | 118.3 | 2.5 | 206.6 | 47.2 | |||||||||||||||||||||||||||
| Other | 227.6 | — | (32.3) | 13.7 | (3.5) | |||||||||||||||||||||||||||
| Total exploration and production | 9,425.6 | 814.5 | 139.1 | 1,198.3 | 535.2 | |||||||||||||||||||||||||||
| Corporate | 822.8 | 0.1 | (46.6) | (97.2) | (124.8) | |||||||||||||||||||||||||||
| Continuing operations | 10,248.4 | 814.6 | 92.5 | 1,101.1 | 410.4 | |||||||||||||||||||||||||||
| Discontinued operations, net of tax | 1.2 | – | (0.6) | – | (0.9) | |||||||||||||||||||||||||||
| Total | $ | 10,249.5 | $ | 814.6 | 91.9 | $ | 1,101.1 | 409.5 | ||||||||||||||||||||||||
| Six Months Ended June 30, 2023 | Six Months Ended June 30, 2022 | |||||||||||||||||||||||||||||||
| (Millions of dollars) | External Revenues | Income (Loss) | External Revenues | Income (Loss) | ||||||||||||||||||||||||||||
| Exploration and production ¹ | ||||||||||||||||||||||||||||||||
| United States | $ | 1,378.5 | 394.9 | $ | 1,685.4 | 744.4 | ||||||||||||||||||||||||||
| Canada | 274.1 | 24.4 | 372.7 | 69.9 | ||||||||||||||||||||||||||||
| Other | 3.6 | (37.6) | 13.7 | (47.7) | ||||||||||||||||||||||||||||
| Total exploration and production | 1,656.2 | 381.7 | 2,071.8 | 766.6 | ||||||||||||||||||||||||||||
| Corporate | 0.1 | (75.2) | (417.8) | (421.1) | ||||||||||||||||||||||||||||
| Continuing operations | 1,656.3 | 306.5 | 1,654.0 | 345.5 | ||||||||||||||||||||||||||||
| Discontinued operations, net of tax | – | (0.3) | – | (1.5) | ||||||||||||||||||||||||||||
| Total | $ | 1,656.3 | 306.2 | $ | 1,654.0 | 344.0 | ||||||||||||||||||||||||||
1 Additional details about results of oil and natural gas operations are presented in the table on pages 27 and 28.
22
Summary
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2023 was $92.5 million, compared to $410.4 million in the in the second quarter of 2022, reflecting a decrease of $317.9 million. Lower net income from continuing operations was largely driven by lower revenues and other income ($286.5 million), increases in exploration expenses ($100.6 million) and higher lease operating expenses ($46.9 million), partially offset by lower income tax expense ($70.2 million). Lower revenues resulted from lower pricing, partially offset by higher sales volumes. Higher exploration costs were the result of dry hole expenses for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico. Increases in lease operating expenses were the result of higher sales volumes while lower income tax expense was the result of lower pre-tax income.
For the six months ended June 30, 2023, the Company reported net income from continuing operations of $306.5 million, compared to $345.5 million in the same period of 2022, reflecting a decrease of $39.0 million. Lower net income from continuing operations was largely driven by higher lease operating expenses ($110.1 million) and increases in exploration expenses ($63.3 million), partially offset by lower other operating expense ($125.9 million). Total revenues and other income were consistent period over period as higher sales volumes and no realized and unrealized losses on derivative instruments were offset by lower pricing for the six months ended June 30, 2023. Increased lease operating expenses relate to higher sales volumes and additional costs associated with workover and maintenance activities at the Gulf of Mexico operations. Higher exploration costs were the result of dry hole expense for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa, and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico. Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.
For the three months ended June 30, 2023, West Texas Intermediate (WTI) crude oil prices averaged approximately $73.78 per barrel (compared to $108.41 in the second quarter of 2022 and $76.13 in the first quarter of 2023). The average price for WTI in June of 2023 was approximately $70.27 per barrel, reflecting a 39% reduction from June of 2022 and a 4% reduction from the average price from March of 2023. The average price in July 2023 was $76.03 per barrel. As of close on August 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were $80.68 and $76.93 per barrel, respectively.
For the three months ended June 30, 2023, the New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged approximately $2.12 per barrel (compared to $7.39 in the second quarter of 2022 and $2.67 in the first quarter of 2023). The average price for NYMEX natural gas in June of 2023 was approximately $2.12 per barrel, reflecting a 72% reduction from June of 2022 and a 9% reduction from the average price from March of 2023. As of close on August 1, 2023, the NYMEX natural gas forward curve prices for the remainder of 2023 and 2024 were $2.95 and $3.45 per barrel, respectively.
For the three months ended June 30, 2023, the Company produced 191 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $362.3 million in capital expenditures (on a value of work done basis), which included $32.3 million in acquisition-related capital. Acquisition-related capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs and seismic data for Côte d’Ivoire in offshore Africa.
For the six months ended June 30, 2023, the Company produced 185 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $698.3 million in capital expenditures (on a value of work done basis), which included acquisition capital of $32.3 million. Acquisition capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa.
During the three and six months ended June 30, 2023, crude oil and condensate, natural gas and natural gas liquids (NGL) volumes from continuing operations were higher than the comparable prior year periods. The increase in production volumes was primarily due to higher production from Khaleesi, Mormont, Samurai field development project, reflecting a full second quarter of production in 2023 (the project started in Q2 2022) and
23
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
increased production from new wells added since the second quarter of 2022. In addition, there were higher gas volumes at Tupper Montney related to new well production. For the three and six months ended June 30, 2023, revenue from production was 30% lower and 19% lower, respectively, compared to the same periods in 2022, primarily driven by the decrease in prices.
For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the Kodiak field in the Gulf of Mexico. The Company reported net income from continuing operations of $410.4 million for the three months ended June 30, 2022; this amount included after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $69.6 million and after-tax losses on contingent consideration of $25.1 million.
During the second quarter of 2022, the Company achieved first production at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, with production flowing through the Murphy-operated King’s Quay floating production system.
In June 2022, the Company also acquired an additional 11.0% working interest (there is no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million.
For the six months ended June 30, 2022, the Company produced 162 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $621.9 million in capital expenditures (on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat -1 exploration well in Brazil. The Company reported net income from continuing operations of $345.5 million for the six months ended June 30, 2022. This amount included after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration adjustments of $79.3 million and $102.3 million, respectively.
24
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Results of Operations
Murphy’s income (loss) by type of business is presented below.
| Income (Loss) | |||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Exploration and production | $ | 139.1 | $ | 535.2 | $ | 381.7 | $ | 766.6 | |||||||||||||||
| Corporate and other | (46.6) | (124.8) | (75.2) | (421.1) | |||||||||||||||||||
| Income from continuing operations | 92.5 | 410.4 | 306.5 | 345.5 | |||||||||||||||||||
| Discontinued operations ¹ | (0.6) | (0.9) | (0.3) | (1.5) | |||||||||||||||||||
| Net income including noncontrolling interest | $ | 91.9 | $ | 409.5 | $ | 306.2 | $ | 344.0 | |||||||||||||||
1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
Exploration and Production
Results of Exploration and Production (E&P) continuing operations are presented by geographic segment below.
| Income (Loss) | |||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
| United States | $ | 168.9 | $ | 491.5 | $ | 394.9 | $ | 744.4 | |||||||||||||||
| Canada | 2.5 | 47.2 | 24.4 | 69.9 | |||||||||||||||||||
| Other | (32.3) | (3.5) | (37.6) | (47.7) | |||||||||||||||||||
| Total | $ | 139.1 | $ | 535.2 | $ | 381.7 | $ | 766.6 | |||||||||||||||
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and Adjusted EBITDA. Management uses EBITDA and Adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and Adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with GAAP.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income attributable to Murphy (GAAP) | $ | 98.3 | $ | 350.6 | $ | 289.9 | $ | 237.2 | |||||||||||||||
| Income tax expense | 34.9 | 105.1 | 88.7 | 88.1 | |||||||||||||||||||
| Interest expense, net | 29.9 | 41.4 | 58.7 | 78.7 | |||||||||||||||||||
| Depreciation, depletion and amortization expense ¹ | 210.1 | 188.2 | 399.3 | 344.8 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | 373.2 | 685.3 | 836.6 | 748.8 | |||||||||||||||||||
| Write-off of previously suspended exploration well | 17.1 | — | 17.1 | — | |||||||||||||||||||
| Accretion of asset retirement obligations ¹ | 10.1 | 10.2 | 20.0 | 20.7 | |||||||||||||||||||
| Foreign exchange loss (gain) | 7.9 | (8.0) | 8.3 | (8.0) | |||||||||||||||||||
| Mark-to-market loss on contingent consideration | 3.2 | 31.7 | 7.1 | 129.8 | |||||||||||||||||||
| Discontinued operations loss | 0.6 | 0.9 | 0.3 | 1.5 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | – | (88.1) | – | 100.4 | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 412.1 | $ | 632.0 | $ | 889.4 | $ | 993.2 | |||||||||||||||
1 Depreciation, depletion and amortization expense and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2023 AND 2022
| (Millions of dollars) | United States 1 | Canada | Other | Total | |||||||||||||||||||
| Three Months Ended June 30, 2023 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 696.2 | $ | 105.3 | $ | — | $ | 801.5 | |||||||||||||||
| Sales of purchased natural gas | — | 13.0 | – | 13.0 | |||||||||||||||||||
| Lease operating expenses | 156.5 | 37.5 | 0.1 | 194.1 | |||||||||||||||||||
| Severance and ad valorem taxes | 12.4 | 0.4 | – | 12.8 | |||||||||||||||||||
| Transportation, gathering and processing | 39.9 | 20.1 | – | 60.0 | |||||||||||||||||||
| Costs of purchased natural gas | — | 9.7 | – | 9.7 | |||||||||||||||||||
| Depreciation, depletion and amortization | 178.0 | 35.0 | — | 213.0 | |||||||||||||||||||
| Accretion of asset retirement obligations | 9.3 | 1.9 | 0.1 | 11.3 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | 79.8 | – | 15.8 | 95.6 | |||||||||||||||||||
| Geological and geophysical | 0.4 | 0.1 | 10.0 | 10.5 | |||||||||||||||||||
| Other exploration | 1.7 | — | 5.3 | 7.0 | |||||||||||||||||||
| 81.9 | 0.1 | 31.1 | 113.1 | ||||||||||||||||||||
| Undeveloped lease amortization | 2.1 | — | 0.6 | 2.7 | |||||||||||||||||||
| Total exploration expenses | 84.0 | 0.1 | 31.7 | 115.8 | |||||||||||||||||||
| Selling and general expenses | (1.9) | 4.7 | 2.6 | 5.4 | |||||||||||||||||||
| Other | 0.5 | 5.4 | 1.4 | 7.3 | |||||||||||||||||||
| Results of operations before taxes | 217.5 | 3.5 | (35.9) | 185.1 | |||||||||||||||||||
| Income tax provisions (benefits) | 48.6 | 1.0 | (3.6) | 46.0 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 168.9 | $ | 2.5 | $ | (32.3) | $ | 139.1 | |||||||||||||||
| Three Months Ended June 30, 2022 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 977.8 | $ | 156.8 | $ | 13.7 | $ | 1,148.3 | |||||||||||||||
| Sales of purchased natural gas | 0.2 | 49.8 | – | 50.0 | |||||||||||||||||||
| Lease operating expenses | 109.5 | 36.9 | 0.9 | 147.3 | |||||||||||||||||||
| Severance and ad valorem taxes | 17.3 | 0.3 | – | 17.6 | |||||||||||||||||||
| Transportation, gathering and processing | 32.3 | 17.6 | – | 49.9 | |||||||||||||||||||
| Costs of purchased natural gas | 0.2 | 47.7 | – | 47.9 | |||||||||||||||||||
| Depreciation, depletion and amortization | 153.7 | 35.6 | 3.4 | 192.7 | |||||||||||||||||||
| Accretion of asset retirement obligations | 9.1 | 2.4 | 0.1 | 11.6 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | (0.7) | – | 2.0 | 1.3 | |||||||||||||||||||
| Geological and geophysical | – | 0.1 | 0.8 | 0.9 | |||||||||||||||||||
| Other exploration | 2.9 | 0.3 | 6.0 | 9.2 | |||||||||||||||||||
| 2.2 | 0.4 | 8.8 | 11.4 | ||||||||||||||||||||
| Undeveloped lease amortization | 2.3 | – | 1.4 | 3.7 | |||||||||||||||||||
| Total exploration expenses | 4.5 | 0.4 | 10.2 | 15.1 | |||||||||||||||||||
| Selling and general expenses | 3.2 | 3.8 | 2.1 | 9.1 | |||||||||||||||||||
| Other | 35.3 | (2.3) | – | 33.0 | |||||||||||||||||||
| Results of operations before taxes | 612.9 | 64.2 | (3.0) | 674.1 | |||||||||||||||||||
| Income tax provisions | 121.4 | 17.0 | 0.5 | 138.9 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 491.5 | $ | 47.2 | $ | (3.5) | $ | 535.2 | |||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2023 AND 2022
| (Millions of dollars) | United States 1 | Canada | Other | Total | |||||||||||||||||||
| Six Months Ended June 30, 2023 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 1,378.5 | $ | 217.2 | $ | 3.6 | $ | 1,599.3 | |||||||||||||||
| Sales of purchased natural gas | – | 56.8 | – | 56.8 | |||||||||||||||||||
| Lease operating expenses | 319.2 | 74.3 | 0.7 | 394.2 | |||||||||||||||||||
| Severance and ad valorem taxes | 23.5 | 0.7 | – | 24.2 | |||||||||||||||||||
| Transportation, gathering and processing | 77.3 | 36.5 | – | 113.8 | |||||||||||||||||||
| Costs of purchased natural gas | – | 41.9 | – | 41.9 | |||||||||||||||||||
| Depreciation, depletion and amortization | 338.2 | 66.7 | 0.9 | 405.8 | |||||||||||||||||||
| Accretion of asset retirement obligations | 18.4 | 3.9 | 0.2 | 22.5 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | 79.6 | – | 16.9 | 96.5 | |||||||||||||||||||
| Geological and geophysical | 0.7 | 0.1 | 10.5 | 11.3 | |||||||||||||||||||
| Other exploration | 3.3 | 0.1 | 9.4 | 12.8 | |||||||||||||||||||
| 83.6 | 0.2 | 36.8 | 120.6 | ||||||||||||||||||||
| Undeveloped lease amortization | 4.1 | 0.1 | 1.2 | 5.4 | |||||||||||||||||||
| Total exploration expenses | 87.7 | 0.3 | 38.0 | 126.0 | |||||||||||||||||||
| Selling and general expenses | 4.5 | 7.1 | 2.8 | 14.4 | |||||||||||||||||||
| Other | 9.9 | 9.7 | 1.4 | 21.0 | |||||||||||||||||||
| Results of operations before taxes | 499.8 | 32.9 | (40.4) | 492.3 | |||||||||||||||||||
| Income tax provisions (benefits) | 104.9 | 8.5 | (2.8) | 110.6 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 394.9 | $ | 24.4 | $ | (37.6) | $ | 381.7 | |||||||||||||||
| Six Months Ended June 30, 2022 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 1,685.2 | $ | 286.1 | $ | 13.7 | $ | 1,985.0 | |||||||||||||||
| Sales of purchased natural gas | 0.2 | 86.6 | – | 86.8 | |||||||||||||||||||
| Lease operating expenses | 209.4 | 73.8 | 0.9 | 284.1 | |||||||||||||||||||
| Severance and ad valorem taxes | 31.5 | 0.7 | – | 32.2 | |||||||||||||||||||
| Transportation, gathering and processing | 61.5 | 35.3 | – | 96.8 | |||||||||||||||||||
| Costs of purchased natural gas | 0.2 | 81.6 | – | 81.8 | |||||||||||||||||||
| Depreciation, depletion and amortization | 280.2 | 69.8 | 3.5 | 353.5 | |||||||||||||||||||
| Accretion of asset retirement obligations | 18.5 | 4.9 | 0.1 | 23.5 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | (0.7) | – | 34.8 | 34.1 | |||||||||||||||||||
| Geological and geophysical | 2.6 | 0.1 | 1.0 | 3.7 | |||||||||||||||||||
| Other exploration | 4.4 | 0.4 | 12.1 | 16.9 | |||||||||||||||||||
| 6.3 | 0.5 | 47.9 | 54.7 | ||||||||||||||||||||
| Undeveloped lease amortization | 4.7 | 0.1 | 3.2 | 8.0 | |||||||||||||||||||
| Total exploration expenses | 11.0 | 0.6 | 51.1 | 62.7 | |||||||||||||||||||
| Selling and general expenses | 11.5 | 8.9 | 4.5 | 24.9 | |||||||||||||||||||
| Other | 138.1 | 2.8 | 0.4 | 141.3 | |||||||||||||||||||
| Results of operations before taxes | 923.5 | 94.5 | (46.8) | 971.2 | |||||||||||||||||||
| Income tax provisions | 179.1 | 24.6 | 0.9 | 204.6 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 744.4 | $ | 69.9 | $ | (47.7) | $ | 766.6 | |||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Exploration and Production
Second quarter 2023 vs. 2022
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
U.S. E&P operations reported earnings of $168.9 million in the second quarter of 2023 compared to earnings of $491.5 million in the second quarter of 2022. Results were $322.6 million unfavorable in the 2023 period compared to the 2022 period primarily due to lower revenues ($281.6 million), higher dry hole and previously suspended exploration costs ($80.5 million), higher lease operating expenses ($47.0 million) and higher depreciation, depletion and amortization expense (DD&A) ($24.3 million), partially offset by lower other expense ($34.8 million) and lower income tax expense ($72.8 million). Lower revenues were primarily due to lower realized prices at Eagle Ford Shale and the Gulf of Mexico, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells at the Khaleesi, Mormont, Samurai development project. Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons. Higher lease operating expenses were primarily due to increased sales volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations. Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico. Lower other expense was primarily due to a lower contingent consideration adjustment of $3.2 million in 2023 (2022: $31.7 million) as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L). Lower income tax expense was a result of lower pre-tax income.
Canadian E&P operations reported earnings of $2.5 million in the second quarter of 2023 compared to earnings of $47.2 million in the second quarter of 2022. Results were unfavorable $44.7 million compared to the 2022 period primarily due to lower revenues ($51.5 million), partially offset by lower income tax expense ($16.0 million). Lower revenues were due to lower oil and gas pricing in the second quarter of 2023 and lower sales volumes primarily as a result of natural decline at Kaybob Duvernay, partially offset by higher natural gas sales volumes and lower royalties at Tupper Montney. Lower income tax expense was a result of lower pre-tax income.
Other international E&P operations reported a loss from continuing operations of $32.3 million in the second quarter of 2023 compared to a loss of $3.5 million in the second quarter of 2022. The result was $28.8 million unfavorable versus the 2022 period primarily due to higher exploration expenses ($21.5 million) and lower revenues from Brunei ($13.7 million). Higher exploration expenses related to the purchase of seismic data for Côte d’Ivoire in offshore Africa and writing off previously suspended exploration costs for the Cholula -1 EXP well in Mexico.
Six months 2023 vs. 2022
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
U.S. E&P operations reported earnings of $394.9 million for the six months ended June 30, 2023, compared to earnings of $744.4 million for the six months ended June 30, 2022. Results were $349.5 million unfavorable in the 2023 period compared to the 2022 period, driven by lower revenues ($306.9 million), higher lease operating expenses ($109.8 million), higher dry hole and previously suspended exploration costs ($80.3 million) and higher DD&A ($58.0 million), partially offset by lower other expense ($128.2 million) and lower income tax expense ($74.2 million). Lower revenues were primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells at Khaleesi, Mormont, Samurai development project. Higher lease operating expenses related to increased sales volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations. Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons. Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico. Lower other expenses was primarily due to a lower contingent consideration adjustment of $7.1 million in 2023 (2022: $129.8 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L). Lower income tax expense was a result of lower pre-tax income.
Canadian E&P operations reported earnings of $24.4 million for the six months ended June 30, 2023, compared to earnings of $69.9 million for the six months ended June 30, 2022. Results were $45.5 million unfavorable compared to the 2022 period. The current year results include lower revenues ($68.9 million), partially offset by lower income tax expense ($16.1 million). Lower revenue was primarily attributable to lower realized prices and
29
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
lower volumes at Kaybob Duvernay primarily due to natural decline, partially offset by higher gas volumes at Tupper Montney related to new wells added and lower royalties. Lower income tax expense was a result of lower pre-tax income.
Other international E&P operations reported a loss of $37.6 million for the six months ended June 30, 2023, compared to a loss of $47.7 million in the prior year. Results were $10.1 million favorable compared to the 2022 period primarily due to lower exploration expenses ($13.1 million), partially offset by lower revenues from Brunei ($10.1 million). Lower exploration expenses were primarily the result of higher dry hole costs in 2022 for Cutthroat -1 exploration well, partially offset by the purchase of seismic data for Côte d’Ivoire in offshore Africa in the current period. During the six months ended June 30, 2023, the Company expensed costs for the previously suspended exploration costs for Cholula -1 EXP well in Block 5 in the Gulf of Mexico, and during the same period in 2022, the Company expensed costs associated with the Cutthroat -1 exploration well in block SEAL-M-428, in the Sergipe-Alagoas Basin offshore Brazil.
Corporate
Second quarter 2023 vs. 2022
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $46.6 million in the second quarter of 2023 compared to a loss of $124.8 million in same period of 2022. The $78.2 million favorable variance was principally due to no current period losses on derivative instruments in the second quarter of 2023 compared to a loss for the same period in 2022 of $103.1 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, with variability in between the floor and ceiling. During the second quarter of 2023 and as of June 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Favorable variances were also recorded due to lower interest expense resulting from overall lower debt levels ($11.6 million), partially offset by lower income tax benefit ($22.4 million). Lower income tax benefit was a result of lower pre-tax losses.
Six months 2023 vs. 2022
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $75.2 million for the six months ended June 30, 2023, compared to a loss of $421.1 million for the six months ended June 30, 2022. The $345.9 million favorable variance was primarily due to no current period losses on derivative instruments for the six months ended June 30, 2023, compared to a loss for the same period in 2022 ($423.8 million) and lower interest expense ($19.9 million), partially offset by lower income tax benefits ($94.4 million) and higher foreign exchange losses ($15.9 million). Interest charges are lower for the six months ended June 30, 2023, primarily due to lower overall debt levels as the Company reduced debt by $647.7 million during 2022 and the Company incurred debt redemption premiums of $3.4 million during the same period in 2022. 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, with variability in between the floor and ceiling. During the six months ended June 30, 2023 and as of June 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Lower income tax benefit was a result of lower pre-tax losses.
30
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Production Volumes and Prices
Second quarter 2023 vs. 2022
Total hydrocarbon production from continuing operations averaged 190,695 barrels of oil equivalent per day in the second quarter of 2023, which was 10% higher than the 173,173 barrels per day produced in second quarter of 2022. The increase in production was principally due to increased production from the Gulf of Mexico primarily attributable to the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore, related primarily to new well production at Tupper Montney.
Average crude oil and condensate production from continuing operations was 105,124 barrels per day in the second quarter of 2023 compared to 98,661 barrels per day in the second quarter of 2022. The increase of 6,463 barrels per day was associated with higher volumes in the Gulf of Mexico (8,595 barrels per day) principally due to a full quarter of production from the Khaleesi, Mormont, Samurai field development project in 2023 and new wells added since the second quarter of 2022. In addition, Canada production was lower (1,537 barrels per day) primarily attributable to natural well declines at Kaybob Duvernay. Eagle Ford Shale production was higher (576 barrels per day) due to new well production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.50 per barrel in the second quarter of 2023 compared to $109.25 per barrel in the same period of 2022 period, a decrease of 33%.
Total production of NGL from continuing operations was 11,177 barrels per day in the second quarter of 2023 compared to 10,950 barrels per day in the second quarter of 2022. The increase of 227 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to increased production from the Khaleesi, Mormont, Samurai field development project, partially offset with lower volumes at Eagle Ford Shale for planned downtime for offset frac impacts. The average sales price for U.S. NGL was $18.71 per barrel in the second quarter of 2023 compared to $39.37 per barrel in the same period of 2022. The average sales price for NGL in Canada was $29.90 per barrel in the second quarter of 2023 compared to $63.99 per barrel in the same period of 2022. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.
Natural gas production volumes from continuing operations averaged 446.4 million cubic feet per day (MMCFD) in the second quarter of 2023 compared to 381.4 MMCFD in the second quarter 2022. The increase of 65.0 MMCFD was primarily the result of higher volumes in Canada (64.2 MMCFD). Higher natural gas volume in Canada is primarily due to new well production and lower natural gas royalty volumes. Natural gas prices for the total Company averaged $1.92 per thousand cubic feet (MCF) in the second quarter of 2023, versus $3.90 per MCF average in the same period of 2022. Average natural gas prices in the U.S. and Canada for the second quarter of 2023 was $2.21 and $1.85 per MCF, respectively.
Six months 2023 vs. 2022
Total hydrocarbon production from Exploration and Production averaged 185,250 barrels of oil equivalent per day for the six months ended June 30, 2023, which represented a 15% increase from the 161,579 barrels per day produced for the six months ended June 30, 2022. The increase was principally due to increased production from the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore primarily due to new wells at Tupper Montney.
Average crude oil and condensate production was 103,067 barrels per day for the six months ended June 30, 2023, compared to 91,154 barrels per day for the six months ended June 30, 2022. The increase of 11,913 barrels per day was principally due to increased production from the Gulf of Mexico largely attributable to the Khaleesi, Mormont, Samurai field development project for new wells added since the second quarter of 2022 (14,487 barrels per day). In addition, Canada production was lower (1,747 barrels per day) primarily due to natural decline at Kaybob Duvernay. Eagle Ford Shale production was lower (234 barrels per day) due to normal well decline partially offset by new well production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.65 per barrel for the six months ended June 30, 2023, compared to $102.86 per barrel in the 2022 period, and decrease of 28.4% year over year.
Total production of NGL was 11,250 barrels per day for the six months ended June 30, 2023, compared to 10,150 barrels per day in the 2022 period. The average sales price for U.S. NGL was $21.44 per barrel in 2023
31
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
compared to $40.00 per barrel in 2022. The average sales price for NGL in Canada was $39.82 per barrel in 2023 compared to $59.23 per barrel in 2022. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.
Natural gas production volumes averaged 425.6 MMCFD for the six months ended June 30, 2023, compared to 361.7 MMCFD in 2022. The increase of 63.9 MMCFD was primarily the result of higher volumes in Canada (55.6 MMCFD) and the Gulf of Mexico (12.6 MMCFD), partially offset by lower volumes at Eagle Ford Shale (4.3 MMCFD). The higher natural gas volumes in Canada were the result of new wells brought into production during the second quarter of 2023 and new wells added since the second quarter of 2022. Natural gas prices for the total Company averaged $2.28 per MCF for the six months ended June 30, 2023, versus $3.54 per MCF average in the same period of 2022. Average realized natural gas prices in the U.S. and Canada for the six months ended June 30, 2023 were $2.66 per MCF and $2.17 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.
Additional details about results of oil and natural gas operations are presented in the tables on pages 27 and 28.
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2023 and 2022.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
| United States | Onshore | 26,880 | 26,304 | 23,100 | 23,334 | |||||||||||||||||||||
Gulf of Mexico 1 | 72,022 | 63,427 | 73,850 | 59,363 | ||||||||||||||||||||||
| Canada | Onshore | 3,097 | 4,419 | 3,190 | 4,400 | |||||||||||||||||||||
| Offshore | 2,913 | 3,128 | 2,687 | 3,224 | ||||||||||||||||||||||
| Other | 212 | 1,383 | 240 | 833 | ||||||||||||||||||||||
| Total net crude oil and condensate - continuing operations | 105,124 | 98,661 | 103,067 | 91,154 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
| United States | Onshore | 4,328 | 5,178 | 4,243 | 5,006 | |||||||||||||||||||||
Gulf of Mexico 1 | 6,291 | 4,913 | 6,316 | 4,223 | ||||||||||||||||||||||
| Canada | Onshore | 558 | 859 | 691 | 921 | |||||||||||||||||||||
| Total net natural gas liquids - continuing operations | 11,177 | 10,950 | 11,250 | 10,150 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
| United States | Onshore | 24,195 | 29,651 | 24,178 | 28,512 | |||||||||||||||||||||
Gulf of Mexico 1 | 69,904 | 63,703 | 72,539 | 59,902 | ||||||||||||||||||||||
| Canada | Onshore | 352,265 | 288,019 | 328,878 | 273,237 | |||||||||||||||||||||
| Total net natural gas - continuing operations | 446,364 | 381,373 | 425,595 | 361,651 | ||||||||||||||||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 190,695 | 173,173 | 185,250 | 161,579 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,949) | (7,962) | (6,279) | (8,044) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (204) | (319) | (218) | (303) | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (1,751) | (3,097) | (2,051) | (2,845) | ||||||||||||||||||||||
Total noncontrolling interest 3 | (6,445) | (8,797) | (6,839) | (8,821) | ||||||||||||||||||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 184,250 | 164,376 | 178,411 | 152,758 | ||||||||||||||||||||||
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.
33
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
The following table contains the weighted average sales prices for the three-month and six-month periods ended June 30, 2023 and 2022.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| (Weighted average Exploration and Production sales prices) | ||||||||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | $ | 72.39 | $ | 110.66 | $ | 73.47 | $ | 103.39 | |||||||||||||||||
Gulf of Mexico 1 | 73.82 | 109.55 | 73.54 | 102.76 | ||||||||||||||||||||||
Canada 2 | Onshore | 68.50 | 100.51 | 71.46 | 96.84 | |||||||||||||||||||||
| Offshore | 80.14 | 115.65 | 79.26 | 113.46 | ||||||||||||||||||||||
| Other | – | 86.51 | 89.05 | 86.51 | ||||||||||||||||||||||
| Natural gas liquids – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | 16.60 | 38.29 | 19.28 | 38.30 | |||||||||||||||||||||
Gulf of Mexico 1 | 20.16 | 40.46 | 22.89 | 41.95 | ||||||||||||||||||||||
Canada 2 | Onshore | 29.90 | 63.99 | 39.82 | 59.23 | |||||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | ||||||||||||||||||||||||||
| United States | Onshore | 1.88 | 7.06 | 2.19 | 5.89 | |||||||||||||||||||||
Gulf of Mexico 1 | 2.33 | 7.52 | 2.81 | 6.43 | ||||||||||||||||||||||
Canada 2 | Onshore | 1.85 | 2.78 | 2.17 | 2.66 | |||||||||||||||||||||
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. See below for additional discussion and analysis of the Company’s cash flows.
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $749.7 million for the six months ended June 30, 2023 compared to $959.2 million during the same period in 2022. The lower cash from operating activities of $209.5 million was primarily attributable to lower revenue from production ($384.8 million), payments of contingent consideration related to prior Gulf of Mexico acquisition ($139.6 million), and higher lease operating expenses ($110.1 million), partially offset by lower realized losses on derivative instruments ($323.5 million) and the timing of working capital settlements ($106.3 million). Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statement of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statement of Cash Flows. As of June 30, 2023, the Company has no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.
34
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Financial Condition (Continued)
Cash Required by Investing Activities
Net cash required by investing activities, including amount expensed, was $694.8 million for the six months ended June 30, 2023 compared to $599.3 million during the same period in 2022. In the second quarter of 2023, the Company accrued for acquisition-related capital of $32.3 million, which consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa (also see Note D). During the six months ended 2022, the Company acquired an 11.0% additional working interest in Kodiak of $46.5 million.
Total accrual basis capital expenditures are shown below.
| Six Months Ended June 30, | |||||||||||
| (Millions of dollars) | 2023 | 2022 | |||||||||
| Capital Expenditures | |||||||||||
| Exploration and production | $ | 688.4 | $ | 611.4 | |||||||
| Corporate | 9.9 | 10.5 | |||||||||
| Total capital expenditures | $ | 698.3 | $ | 621.9 | |||||||
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| Six Months Ended June 30, | |||||||||||
| (Millions of dollars) | 2023 | 2022 | |||||||||
| Property additions and dry hole costs per cash flow statements | $ | 694.8 | $ | 552.8 | |||||||
| Acquisition of oil and gas properties | – | 46.5 | |||||||||
| Geophysical and other exploration expenses | 20.0 | 16.3 | |||||||||
| Capital expenditure accrual changes and other | (16.5) | 6.3 | |||||||||
| Total capital expenditures | $ | 698.3 | $ | 621.9 | |||||||
The increase in capital expenditures in the exploration and production business in six months ended June 30, 2023 compared to the same period in 2022 was primarily attributable to development drilling activities at Eagle Ford Shale assets, development drilling at Samurai and St. Malo fields in the Gulf of Mexico, and exploration drilling at Chinook #7, Oso #1 and Longclaw #1 within the Gulf of Mexico. Costs associated with Chinook #7 were expensed to dry hole costs in the second quarter of 2023 as the Company determined there were non- commercial hydrocarbons present. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the third quarter of 2023.
Cash Required by Financing Activities
Net cash required by financing activities was $176.6 million for the six months ended June 30, 2023 compared to $447.5 million during the same period in 2022. In 2023, the cash used in financing activities was principally for the payment of contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section, cash dividends to shareholders of $0.55 per share ($85.9 million) and distributions to the non-controlling interest in the Gulf of Mexico ($16.0 million).
As of June 30, 2023 and in the event it is required to fund investing activities from borrowings, the Company has $769.6 million available on its committed RCF.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Financial Condition (Continued)
Working Capital
As of June 30, 2023, working capital (total current assets less total current liabilities) amounted to a net working capital liability of $165.4 million, $120.1 million lower than December 31, 2022, with the favorable decrease primarily attributable to lower other accrued liabilities ($307.8 million), partially offset with higher accounts payable ($40.3 million), higher operating lease liabilities ($37.9 million) and a lower cash balance ($122.6 million). Lower accrued liabilities were primarily due to payments made for contingent consideration obligation from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made during the six months ended June 30, 2023. Higher accounts payable was primarily due to increased drilling and completions activities and an increase in current payables for abandonment activities, partially offset by the decrease in unrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts outstanding during 2023. Higher current operating lease liabilities were associated with scheduled rate increases for a drilling vessel resulting in additional amounts being reclassified from long-term to current operating lease liabilities.
Capital Employed
At June 30, 2023, long-term debt of $1,823.5 million had increased by $1.1 million compared to December 31, 2022, primarily as a result of normal debt issuance cost amortization. The total of the fixed-rate notes had a weighted average maturity of 7.2 years and a weighted average coupon of 6.1%.
A summary of capital employed at June 30, 2023 and December 31, 2022 follows.
| June 30, 2023 | December 31, 2022 | ||||||||||||||||||||||
| (Millions of dollars) | Amount | % | Amount | % | |||||||||||||||||||
| Capital employed | |||||||||||||||||||||||
| Long-term debt | $ | 1,823.5 | 25.8 | % | $ | 1,822.4 | 26.7 | % | |||||||||||||||
| Murphy shareholders' equity | 5,234.3 | 74.2 | % | 4,994.8 | 73.3 | % | |||||||||||||||||
| Total capital employed | $ | 7,057.8 | 100.0 | % | $ | 6,817.2 | 100.0 | % | |||||||||||||||
Cash and invested cash are maintained in several operating locations outside the U.S. As of June 30, 2023, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $76.9 million, the majority of which was held in Mexico ($21.1 million), Canada ($20.8 million), U.K. ($11.8 million), Brunei ($8.8 million) and Spain ($8.2 million). 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.
On July 31, 2023 the Company entered into a purchase and sale agreement to sell a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash consideration of C$150 million. The transaction is anticipated to close in the third quarter of 2023, subject to closing conditions and adjustments.
Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements
Outlook
Prices for the Company’s primary products are often volatile. The price of crude oil is primarily affected by the levels of supply and demand for energy. As discussed in the Summary section on page 23, lower average crude oil price during the second quarter of 2023 directly impacts the Company’s product revenue from sales. NYMEX WTI pricing for recent and comparable periods was as follows: Q2 2023 $73.78; Q1 2023 $76.13; Q2 2022 $108.41. As of close on August 1, 2023 the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were lower at $80.68 and $76.93 per barrel, respectively; however, we cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash flows. For the third quarter of 2023, production is expected to average between 188.0 and 196.0 thousand barrels of oil equivalents (MBOEPD), excluding noncontrolling interest.
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The Company’s capital expenditure spend for 2023 is expected to be between $950.0 million and $1,025.0 million, excluding noncontrolling interest. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2023 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), including proceeds from the Company’s divestiture of a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction. Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note E).
As of August 1, 2023, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
| Volumes (MMcf/d) | Price/Mcf | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 250 | C$2.35 | 7/1/2023 | 12/31/2023 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 162 | C$2.39 | 1/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 25 | US$1.98 | 7/1/2023 | 10/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 15 | US$1.98 | 11/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
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Forward-Looking Statements
This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, 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, banking system 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 our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) and on page 40 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy, at times, makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were no derivative commodity contracts in place at June 30, 2023.
There were no derivative foreign exchange contracts in place at June 30, 2023.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended June 30, 2023, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2022 Form 10-K filed on February 27, 2023. The Company has not identified any additional risk factors not previously disclosed in its 2022 Form 10-K report.
ITEM 6. EXHIBITS
The Exhibit Index on page 42 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| MURPHY OIL CORPORATION | ||||||||
| (Registrant) | ||||||||
| By | /s/ PAUL D. VAUGHAN | |||||||
| Paul D. Vaughan | ||||||||
| Vice President and Controller | ||||||||
| (Chief Accounting Officer and Duly Authorized Officer) | ||||||||
August 3, 2023
(Date)
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EXHIBIT INDEX
The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.
| Exhibit No. | ||||||||
| 101. INS | Inline XBRL Instance Document | |||||||
| 101. SCH | Inline XBRL Taxonomy Extension Schema Document | |||||||
| 101. CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| 101. DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | |||||||
| 101. LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document | |||||||
| 101. PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||||||
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