UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended SeptemberJune 30, 20222023
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 1-32414
W&T OFFSHORE, INC.
(Exact name of registrant as specified in its charter)
| ||
Texas |
| 72-1121985 |
(State or other jurisdiction of | | ( |
| |
|
5718 Westheimer Road, Suite 700, Houston, Texas | | 77057-5745 |
(Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code:(713) 626-8525
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of each class |
| Trading Symbol(s) |
| Name of each exchange on which registered |
Common Stock, par value $0.00001 |
| WTI |
| 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 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. Yes ☐ No ☑
As of OctoberJuly 31, 20222023 there were 143,161,608146,480,637 shares outstanding of the registrant’s common stock, par value $0.00001.
W&T OFFSHORE, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
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Condensed Consolidated Balance Sheets as of | 1 | |
2 | ||
3 | ||
4 | ||
5 | ||
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
| | | | | | |
| | September 30, | | December 31, | ||
|
| 2022 |
| 2021 | ||
Assets |
| |
|
| |
|
Current assets: |
| |
|
| |
|
Cash and cash equivalents | | $ | 447,130 | | $ | 245,799 |
Restricted cash | | | 4,417 | | | 4,417 |
Receivables: | |
| | |
| |
Oil and natural gas sales | |
| 89,195 | |
| 54,919 |
Joint interest, net | |
| 16,815 | |
| 9,745 |
Total receivables | |
| 106,010 | |
| 64,664 |
Prepaid expenses and other assets (Note 1) | |
| 53,014 | |
| 43,379 |
Total current assets | |
| 610,571 | |
| 358,259 |
| | | | | | |
Oil and natural gas properties and other, net (Note 1) | |
| 729,958 | |
| 665,252 |
| | | | | | |
Restricted deposits for asset retirement obligations | |
| 21,760 | |
| 16,019 |
Deferred income taxes | |
| 62,334 | |
| 102,505 |
Other assets (Note 1) | |
| 65,681 | |
| 51,172 |
Total assets | | $ | 1,490,304 | | $ | 1,193,207 |
Liabilities and Shareholders’ Deficit | |
|
| |
|
|
Current liabilities: | |
|
| |
|
|
Accounts payable | | $ | 72,051 | | $ | 67,409 |
Undistributed oil and natural gas proceeds | |
| 59,518 | |
| 36,243 |
Advances from joint interest partners | |
| 3,017 | |
| 15,072 |
Asset retirement obligations | |
| 54,886 | |
| 56,419 |
Accrued liabilities (Note 1) | |
| 154,236 | |
| 106,140 |
Current portion of long-term debt | | | 35,450 | | | 42,960 |
Income tax payable | |
| 1,613 | |
| 133 |
Total current liabilities | |
| 380,771 | |
| 324,376 |
| | | | | | |
Long-term debt, net (Note 2) | |
| 665,973 | |
| 687,938 |
Asset retirement obligations, less current portion | |
| 398,724 | |
| 368,076 |
Other liabilities (Note 1) | |
| 94,841 | |
| 55,389 |
Deferred income taxes | |
| 113 | |
| 113 |
Commitments and contingencies (Note 12) | |
| 4,899 | |
| 4,495 |
Shareholders’ deficit: | |
|
| |
|
|
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at September 30, 2022 and December 31, 2021 | |
| — | |
| — |
Common stock, $0.00001 par value; 200,000 shares authorized; 146,031 issued and 143,162 outstanding at September 30, 2022; 145,732 issued and 142,863 outstanding at December 31, 2021 | |
| 1 | |
| 1 |
Additional paid-in capital | |
| 557,386 | |
| 552,923 |
Retained deficit | |
| (588,237) | |
| (775,937) |
Treasury stock, at cost; 2,869 shares at September 30, 2022 and December 31, 2021 | |
| (24,167) | |
| (24,167) |
Total shareholders’ deficit | |
| (55,017) | |
| (247,180) |
Total liabilities and shareholders’ deficit | | $ | 1,490,304 | | $ | 1,193,207 |
| | | | | | |
| | June 30, | | December 31, | ||
|
| 2023 |
| 2022 | ||
Assets |
| |
|
| |
|
Current assets: |
| |
|
| |
|
Cash and cash equivalents | | $ | 171,627 | | $ | 461,357 |
Restricted cash | | | 4,417 | | | 4,417 |
Receivables: | |
| | |
| |
Oil and natural gas sales | |
| 41,342 | |
| 66,146 |
Joint interest, net | |
| 13,875 | |
| 14,000 |
Income taxes | |
| 1,941 | |
| — |
Total receivables | |
| 57,158 | |
| 80,146 |
Prepaid expenses and other assets (Note 1) | |
| 21,365 | |
| 24,343 |
Total current assets | |
| 254,567 | |
| 570,263 |
| | | | | | |
Oil and natural gas properties and other, net (Note 1) | |
| 737,740 | |
| 735,215 |
| | | | | | |
Restricted deposits for asset retirement obligations | |
| 22,092 | |
| 21,483 |
Deferred income taxes | |
| 45,700 | |
| 57,280 |
Other assets (Note 1) | |
| 42,118 | |
| 47,549 |
Total assets | | $ | 1,102,217 | | $ | 1,431,790 |
Liabilities and Shareholders’ Equity | |
|
| |
|
|
Current liabilities: | |
|
| |
|
|
Accounts payable | | $ | 67,293 | | $ | 65,158 |
Undistributed oil and natural gas proceeds | |
| 31,178 | |
| 41,934 |
Advances from joint interest partners | |
| 3,110 | |
| 3,181 |
Asset retirement obligations (Note 7) | |
| 37,763 | |
| 25,359 |
Accrued liabilities (Note 1) | |
| 39,323 | |
| 74,041 |
Current portion of long-term debt, net | | | 30,550 | | | 582,249 |
Income tax payable | |
| 10 | |
| 412 |
Total current liabilities | |
| 209,227 | |
| 792,334 |
Long-term debt (Note 2) | |
|
| |
|
|
Principal | |
| 382,697 | |
| 114,158 |
Unamortized debt issuance costs | |
| (9,676) | |
| (2,970) |
Long-term debt, net (Note 2) | |
| 373,021 | |
| 111,188 |
| | | | | | |
Asset retirement obligations, less current portion (Note 7) | |
| 443,069 | |
| 441,071 |
Other liabilities (Note 1) | |
| 35,041 | |
| 59,134 |
Deferred income taxes | |
| 72 | |
| 72 |
Commitments and contingencies (Note 11) | |
| 16,996 | |
| 20,357 |
Shareholders’ equity: | |
|
| |
|
|
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at June 30, 2023 and December 31, 2022 | |
| — | |
| — |
Common stock, $0.00001 par value; 200,000 shares authorized; 149,350 issued and 146,481 outstanding at June 30, 2023; 149,002 issued and 146,133 outstanding at December 31, 2022 | |
| 1 | |
| 1 |
Additional paid-in capital | |
| 579,849 | |
| 576,588 |
Retained deficit | |
| (530,892) | |
| (544,788) |
Treasury stock, at cost; 2,869 shares at June 30, 2023 and December 31, 2022 | |
| (24,167) | |
| (24,167) |
Total shareholders’ equity | |
| 24,791 | |
| 7,634 |
Total liabilities and shareholders’ equity | | $ | 1,102,217 | | $ | 1,431,790 |
See Notes to Condensed Consolidated Financial Statements.
1
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||||||||||
|
| 2022 |
| 2021 |
| 2022 |
| 2021 |
| 2023 |
| 2022 |
| 2023 |
| 2022 | ||||||||
Revenues: |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Oil | | $ | 130,560 | | $ | 74,265 | | $ | 412,526 | | $ | 240,418 | | $ | 89,982 | | $ | 159,264 | | $ | 186,982 | | $ | 281,966 |
NGLs | |
| 16,875 | |
| 12,205 | |
| 47,430 | |
| 30,397 | |
| 10,385 | |
| 16,735 | |
| 18,180 | |
| 30,555 |
Natural gas | |
| 113,673 | |
| 45,137 | |
| 257,452 | |
| 113,816 | |
| 23,438 | |
| 92,413 | |
| 48,242 | |
| 143,779 |
Other | |
| 5,377 | |
| 2,339 | |
| 13,889 | |
| 7,790 | |
| 2,376 | |
| 5,396 | |
| 4,502 | |
| 8,512 |
Total revenues | |
| 266,485 | |
| 133,946 | |
| 731,297 | |
| 392,421 | |
| 126,181 | |
| 273,808 | |
| 257,906 | |
| 464,812 |
Operating expenses: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Lease operating expenses | |
| 59,010 | |
| 39,490 | |
| 155,397 | |
| 129,399 | |
| 66,021 | |
| 52,976 | |
| 131,207 | |
| 96,387 |
Gathering, transportation and production taxes | | | 12,199 | | | 6,593 | | | 26,647 | | | 19,687 | | | 6,802 | | | 9,181 | | | 12,938 | | | 14,448 |
Depreciation, depletion, and amortization | |
| 27,493 | |
| 20,818 | |
| 79,848 | |
| 66,511 | |
| 28,177 | |
| 27,679 | |
| 50,801 | |
| 52,354 |
Asset retirement obligations accretion | | | 6,620 | | | 5,473 | | | 19,536 | | | 17,368 | | | 7,717 | | | 6,681 | | | 15,227 | | | 12,917 |
General and administrative expenses | |
| 23,047 | |
| 13,391 | |
| 51,790 | |
| 38,090 | |
| 17,393 | |
| 14,967 | |
| 37,312 | |
| 28,743 |
Total operating expenses | |
| 128,369 | |
| 85,765 | |
| 333,218 | |
| 271,055 | |
| 126,110 | |
| 111,484 | |
| 247,485 | |
| 204,849 |
Operating income | |
| 138,116 | |
| 48,181 | |
| 398,079 | |
| 121,366 | |
| 71 | |
| 162,324 | |
| 10,421 | |
| 259,963 |
| | | | | | | | | | | | | | | | | | | | | | | | |
Interest expense, net | |
| 16,849 | |
| 18,910 | |
| 54,915 | |
| 50,474 | |
| 10,323 | |
| 18,183 | |
| 25,036 | |
| 38,066 |
Derivative loss | |
| 38,749 | |
| 73,137 | |
| 109,892 | |
| 179,156 | ||||||||||||
Derivative (gain) loss, net | |
| (829) | |
| (8,854) | |
| (40,069) | |
| 71,143 | ||||||||||||
Other (income) expense, net | |
| (600) | |
| — | |
| (1,229) | |
| 964 | |
| (311) | |
| (1,534) | |
| (78) | |
| (629) |
Income (loss) before income taxes | |
| 83,118 | |
| (43,866) | |
| 234,501 | |
| (109,228) | |
| (9,112) | |
| 154,529 | |
| 25,532 | |
| 151,383 |
Income tax expense (benefit) | |
| 16,397 | |
| (5,902) | |
| 46,801 | |
| (18,846) | ||||||||||||
Net income (loss) | | $ | 66,721 | | $ | (37,964) | | $ | 187,700 | | $ | (90,382) | ||||||||||||
Income tax expense | |
| 2,997 | |
| 31,093 | |
| 11,636 | |
| 30,404 | ||||||||||||
Net (loss) income | | $ | (12,109) | | $ | 123,436 | | $ | 13,896 | | $ | 120,979 | ||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
Net income (loss) per common share: | | | | | | | | | | | | | ||||||||||||
Net income per common share: | | | | | | | | | | | | | ||||||||||||
Basic | | $ | 0.46 | | $ | (0.27) | | $ | 1.30 | | $ | (0.64) | | $ | (0.08) | | $ | 0.86 | | $ | 0.09 | | $ | 0.85 |
Diluted | | $ | 0.46 | | $ | (0.27) | | $ | 1.30 | | $ | (0.64) | | $ | (0.08) | | $ | 0.85 | | $ | 0.09 | | $ | 0.84 |
| | | | | | | | | | | | | ||||||||||||
Weighted average common shares outstanding | | | | | | | | | | | | | ||||||||||||
Weighted average common shares outstanding: | | | | | | | | | | | | | ||||||||||||
Basic | | | 143,116 | | | 142,297 | | | 143,026 | | | 142,231 | | | 146,452 | | | 143,020 | | | 146,435 | | | 142,981 |
Diluted | | | 145,882 | | | 142,297 | | | 144,696 | | | 142,231 | | | 146,452 | | | 144,525 | | | 149,045 | | | 144,094 |
See Notes to Condensed Consolidated Financial Statements.
2
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICITEQUITY (DEFICIT)
(In thousands)
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit | |||||
Balances at June 30, 2022 |
| 143,155 |
| $ | 1 |
| $ | 554,755 |
| $ | (654,958) |
| 2,869 |
| $ | (24,167) |
| $ | (124,369) |
Share-based compensation |
| — |
|
| — |
|
| 2,645 |
|
| — |
| — |
|
| — |
|
| 2,645 |
Stock Issued |
| 7 |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
RSUs surrendered for payroll taxes |
| — |
|
| — |
|
| (14) |
|
| — |
| — |
|
| — |
|
| (14) |
Net income |
| — |
|
| — |
|
| — |
|
| 66,721 |
| — |
|
| — |
|
| 66,721 |
Balances at September 30, 2022 |
| 143,162 |
| $ | 1 |
| $ | 557,386 |
| $ | (588,237) |
| 2,869 |
| $ | (24,167) |
| $ | (55,017) |
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit | |||||
Balances at June 30, 2021 |
| 142,367 |
| $ | 1 |
| $ | 551,260 |
| $ | (786,877) |
| 2,869 |
| $ | (24,167) |
| $ | (259,783) |
Share-based compensation |
| — |
|
| — |
|
| 858 |
|
| — |
| — |
|
| — |
|
| 858 |
Stock Issued |
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
Net loss |
| — |
|
| — |
|
| — |
|
| (37,964) |
| — |
|
| — |
|
| (37,964) |
Balances at September 30, 2021 |
| 142,367 |
| $ | 1 |
| $ | 552,118 |
| $ | (824,841) |
| 2,869 |
| $ | (24,167) |
| $ | (296,889) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ||
|
| Common Stock |
| Additional |
| | |
| |
| |
| Total |
| Common Stock |
| Additional |
| | |
| |
| |
| Total | ||||||||||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | ||||||||||||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit |
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Equity | ||||||||||
Balances at December 31, 2021 |
| 142,863 | | $ | 1 | | $ | 552,923 | | $ | (775,937) |
| 2,869 | | $ | (24,167) | | $ | (247,180) | |||||||||||||||||||
Balances at March 31, 2023 |
| 146,461 |
| $ | 1 |
| $ | 577,787 |
| $ | (518,783) |
| 2,869 |
| $ | (24,167) |
| $ | 34,838 | |||||||||||||||||||
Share-based compensation |
| — | |
| — | |
| 5,179 | |
| — |
| — | |
| — | |
| 5,179 |
| — |
|
| — |
|
| 2,087 |
|
| — |
| — |
| — |
|
| 2,087 | |
Stock Issued | | 299 | | | — | | | — | | | — | | — | | — | | | — | ||||||||||||||||||||
Stock issued |
| 20 |
|
| — |
|
| — |
|
| — |
| — |
| — |
|
| — | ||||||||||||||||||||
RSUs surrendered for payroll taxes |
| — |
|
| — |
|
| (716) |
|
| — |
| — |
| — |
|
| (716) |
| — |
|
| — |
|
| (25) |
|
| — |
| — |
| — |
|
| (25) | ||
Net income |
| — | |
| — | |
| — | |
| 187,700 |
| — | |
| — | |
| 187,700 | |||||||||||||||||||
Balances at September 30, 2022 |
| 143,162 | | $ | 1 | | $ | 557,386 | | $ | (588,237) |
| 2,869 | | $ | (24,167) | | $ | (55,017) | |||||||||||||||||||
Net loss |
| — |
|
| — |
|
| — |
|
| (12,109) |
| — |
|
| — |
|
| (12,109) | |||||||||||||||||||
Balances at June 30, 2023 |
| 146,481 |
| $ | 1 |
| $ | 579,849 |
| $ | (530,892) |
| 2,869 |
| $ | (24,167) |
| $ | 24,791 |
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit | |||||
Balances at December 31, 2020 |
| 142,305 | | $ | 1 | | $ | 550,339 | | $ | (734,459) |
| 2,869 | | $ | (24,167) | | $ | (208,286) |
Share-based compensation |
| — | |
| — | |
| 1,779 | |
| — |
| — | |
| — | |
| 1,779 |
Stock Issued | | 62 | | | — | | | — | | | — | | — | | | — | | | — |
Net loss |
| — | |
| — | |
| — | |
| (90,382) |
| — | |
| — | |
| (90,382) |
Balances at September 30, 2021 |
| 142,367 | | $ | 1 | | $ | 552,118 | | $ | (824,841) |
| 2,869 | | $ | (24,167) | | $ | (296,889) |
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit | |||||
Balances at March 31, 2022 |
| 143,012 |
| $ | 1 |
| $ | 553,175 |
| $ | (778,394) |
| 2,869 |
| $ | (24,167) |
| $ | (249,385) |
Share-based compensation |
| — |
|
| — |
|
| 2,014 |
|
| — |
| — |
|
| — |
|
| 2,014 |
Stock issued |
| 143 |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
RSUs surrendered for payroll taxes |
| — |
|
| — |
|
| (434) |
|
| — |
| — |
|
| — |
|
| (434) |
Net income |
| — |
|
| — |
|
| — |
|
| 123,436 |
| — |
|
| — |
|
| 123,436 |
Balances at June 30, 2022 |
| 143,155 |
| $ | 1 |
| $ | 554,755 |
| $ | (654,958) |
| 2,869 |
| $ | (24,167) |
| $ | (124,369) |
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Equity | |||||
Balances at December 31, 2022 |
| 146,133 | | $ | 1 | | $ | 576,588 | | $ | (544,788) |
| 2,869 | | $ | (24,167) | | $ | 7,634 |
Share-based compensation |
| — | |
| — | |
| 4,009 | |
| — |
| — | |
| — | |
| 4,009 |
Stock issued | | 348 | | | — | | | — | | | — | | — | | | — | | | — |
RSUs surrendered for payroll taxes |
| — |
|
| — |
|
| (748) |
|
| — |
| — |
|
| — |
|
| (748) |
Net income |
| — | |
| — | |
| — | |
| 13,896 |
| — | |
| — | |
| 13,896 |
Balances at June 30, 2023 |
| 146,481 | | $ | 1 | | $ | 579,849 | | $ | (530,892) |
| 2,869 | | $ | (24,167) | | $ | 24,791 |
| | | | | | | | | | | | | | | | | | | |
|
| Common Stock |
| Additional |
| | |
| |
|
| |
| Total | |||||
| | Outstanding | | Paid-In | | Retained | | Treasury Stock | | Shareholders’ | |||||||||
|
| Shares |
| Value |
| Capital |
| Deficit |
| Shares |
| Value |
| Deficit | |||||
Balances at December 31, 2021 |
| 142,863 | | $ | 1 | | $ | 552,923 | | $ | (775,937) |
| 2,869 | | $ | (24,167) | | $ | (247,180) |
Share-based compensation |
| — | |
| — | |
| 2,534 | |
| — |
| — | |
| — | |
| 2,534 |
Stock issued | | 292 | | | — | | | — | | | — | | — | | | — | | | — |
RSUs surrendered for payroll taxes |
| — |
|
| — |
|
| (702) |
|
| — |
| — |
|
| — |
|
| (702) |
Net income |
| — | |
| — | |
| — | |
| 120,979 |
| — | |
| — | |
| 120,979 |
Balances at June 30, 2022 |
| 143,155 | | $ | 1 | | $ | 554,755 | | $ | (654,958) |
| 2,869 | | $ | (24,167) | | $ | (124,369) |
See Notes to Condensed Consolidated Financial Statements.
3
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| | | | | | |
| | Nine Months Ended September 30, | ||||
|
| 2022 |
| 2021 | ||
Operating activities: |
| |
|
| |
|
Net income (loss) | | $ | 187,700 | | $ | (90,382) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
|
| |
|
|
Depreciation, depletion, amortization and accretion | |
| 99,384 | |
| 83,879 |
Amortization of debt items and other items | |
| 6,114 | |
| 4,095 |
Share-based compensation | |
| 5,179 | |
| 1,779 |
Derivative loss | |
| 109,892 | |
| 179,156 |
Derivative cash (payments) receipts, net | |
| (1,022) | |
| (39,554) |
Derivative cash premium payments | | | (46,111) | | | (32,368) |
Deferred income taxes | |
| 40,171 | |
| (18,826) |
Changes in operating assets and liabilities: | |
|
| |
|
|
Oil and natural gas receivables | |
| (34,276) | |
| 504 |
Joint interest receivables | |
| (7,070) | |
| (2,172) |
Prepaid expenses and other assets | |
| (26,816) | |
| (30,473) |
Income tax | |
| 1,480 | |
| (153) |
Asset retirement obligation settlements | |
| (61,285) | |
| (19,744) |
Cash advances from JV partners | |
| (12,055) | |
| 9,999 |
Accounts payable, accrued liabilities and other | |
| 65,566 | |
| 65,551 |
Net cash provided by operating activities | |
| 326,851 | |
| 111,291 |
Investing activities: | |
|
| |
|
|
Investment in oil and natural gas properties and equipment | |
| (29,966) | |
| (16,025) |
Changes in operating assets and liabilities associated with investing activities | |
| (8,237) | |
| 3,619 |
Acquisition of property interests | |
| (51,474) | |
| — |
Net cash used in investing activities | |
| (89,677) | |
| (12,406) |
Financing activities: | |
|
| |
|
|
Repayments on credit facility | |
| — | |
| (80,000) |
Proceeds from Term Loan | |
| — | |
| 215,000 |
Repayments on Term Loan | |
| (33,837) | |
| (11,778) |
Debt issuance costs | |
| (1,290) | |
| (8,249) |
Other | | | (716) | | | — |
Net cash (used in) provided by financing activities | |
| (35,843) | |
| 114,973 |
Increase in cash and cash equivalents | |
| 201,331 | |
| 213,858 |
Cash and cash equivalents and restricted cash, beginning of period | |
| 250,216 | |
| 43,726 |
Cash and cash equivalents and restricted cash, end of period | | $ | 451,547 | | $ | 257,584 |
| | | | | | |
| | Six Months Ended June 30, | ||||
|
| 2023 |
| 2022 | ||
Operating activities: |
| |
|
| |
|
Net income | | $ | 13,896 | | $ | 120,979 |
Adjustments to reconcile net income to net cash provided by operating activities: | |
|
| |
|
|
Depreciation, depletion, amortization and accretion | |
| 66,028 | |
| 65,271 |
Amortization and write off of debt issuance costs | |
| 4,363 | |
| 4,365 |
Share-based compensation | |
| 4,009 | |
| 2,534 |
Derivative (gain) loss | |
| (40,069) | |
| 71,143 |
Derivative cash (payments) receipts, net | |
| (4,427) | |
| 70,227 |
Derivative cash premium payments | | | — | | | (46,111) |
Deferred income taxes | |
| 11,580 | |
| 27,031 |
Changes in operating assets and liabilities: | |
|
| |
|
|
Oil and natural gas receivables | |
| 24,804 | |
| (44,236) |
Joint interest receivables | |
| 125 | |
| (3,625) |
Prepaid expenses and other assets | |
| 26,992 | |
| (30,092) |
Income tax | |
| (2,345) | |
| 3,223 |
Asset retirement obligation settlements | |
| (11,841) | |
| (39,775) |
Cash advances from JV partners | |
| (71) | |
| (9,813) |
Accounts payable, accrued liabilities and other | |
| (43,412) | |
| 46,638 |
Net cash provided by operating activities | |
| 49,632 | |
| 237,759 |
Investing activities: | |
|
| |
|
|
Investment in oil and natural gas properties and equipment | |
| (22,999) | |
| (25,489) |
Changes in operating assets and liabilities associated with investing activities | |
| (2,338) | |
| (5,786) |
Acquisition of property interests | |
| — | |
| (47,625) |
Purchase of corporate aircraft (Note 12) | | | (8,983) | | | — |
Purchases of furniture, fixtures and other | |
| (218) | |
| — |
Net cash used in investing activities | |
| (34,538) | |
| (78,900) |
Financing activities: | |
|
| |
|
|
Repayment of Note Payable | | | (183) | | | — |
Issuance of 11.75% Senior Second Lien Notes | | | 275,000 | | | — |
Repayments on 9.75% Second Senior Lien Notes | | | (552,460) | | | — |
Repayments on Term Loan | |
| (19,181) | |
| (24,941) |
Debt issuance costs | |
| (7,252) | |
| (1,290) |
Other | |
| (748) | |
| (703) |
Net cash used in financing activities | |
| (304,824) | |
| (26,934) |
(Decrease) increase in cash and cash equivalents | |
| (289,730) | |
| 131,925 |
Cash and cash equivalents and restricted cash, beginning of period | |
| 465,774 | |
| 250,216 |
Cash and cash equivalents and restricted cash, end of period | | $ | 176,044 | | $ | 382,141 |
See Notes to Condensed Consolidated Financial Statements.
4
NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T” or the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Interests in fields, leases, structures and equipment are primarily owned by the Company and its 100% owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC (“A-I, LLC”), and Aquasition II, LLC (“A-II LLC”), and through a proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 6 – Joint Venture Drilling Program.
Basis of Presentation
The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim periods and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements for annual periods. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.
Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s 20212022 Annual Report on Form 10-K (the “2021“2022 Annual Report”).
Reclassification – For presentation purposes, as of September 30, 2021, Derivative (gain) loss has been reclassified from “Operating income” on the Condensed Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassification had no effect on the Company’s results of operations, financial position or cash flows.
For presentation purposes, as of September 30, 2021, Gathering and transportation and Production taxes have been combined into one line item within “Operating income” on the Condensed Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassification had no effect on the Company’s results of operations, financial position or cash flows.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
5
Summary of Significant Accounting Policies
Revenue and Accounts Receivable – The Company records revenues from the sale of oil, natural gas liquids (“NGLs”) and natural gas based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. Revenue from the sale of crude oil, natural gas liquids (“NGLs”)NGLs and natural gas is recognized when performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of crude oil, NGLs and natural gas to the customer. RevenueEach unit of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is concentrated with certain major oil and gas companies. There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2022.not required.
The Company also has receivables related to joint interest arrangements primarily with mid-size oil and gas companies with a substantial majority of the net receivable balance concentrated in less than ten companies. A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and forecasts of future economic conditions. The Company’s maximum exposure at any time would be the receivable balance. Joint interest receivables on the Condensed Consolidated Balance Sheets are presented net of allowance for credit losses of $11.6$11.3 million and $10.0$12.1 million as of SeptemberJune 30, 20222023 and December 31, 2021,2022, respectively.
Employee Retention Credit – Under the Consolidated Appropriations Act of 2021, the Company recognized a $2.1$2.2 million employee retention credit during the ninesix months ended SeptemberJune 30, 20212023, which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations. No such credit has been recognized during the nine months ended September 30, 2022.
5
Prepaid Expenses and Other Assets – The amounts recorded are expected to be realized within one year and the major categories are presented in the following table (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 |
| December 31, 2021 | | June 30, 2023 |
| December 31, 2022 | ||||
Derivatives(1) (Note 8) | | $ | 28,747 | | $ | 21,086 | ||||||
Derivatives(1) (Note 4) | | $ | 1,778 | | $ | 4,954 | ||||||
Unamortized insurance/bond premiums | |
| 7,475 | |
| 5,400 | |
| 8,303 | |
| 6,046 |
Prepaid deposits related to royalties | |
| 12,978 | |
| 8,441 | |
| 6,822 | |
| 9,139 |
Prepayment to vendors | |
| 1,213 | |
| 4,522 | ||||||
Prepayments to vendors | |
| 1,628 | |
| 1,767 | ||||||
Prepayments to joint interest partners | | | 1,953 | | | 2,808 | | | 2,319 | | | 1,717 |
Debt issue costs | | | 604 | | | 1,065 | | | 427 | | | 687 |
Other | |
| 44 | |
| 57 | |
| 88 | |
| 33 |
Prepaid expenses and other assets | | $ | 53,014 | | $ | 43,379 | | $ | 21,365 | | $ | 24,343 |
(1) | Includes closed contracts which have not yet settled. |
Oil and Natural Gas Properties and Other, Net – Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 |
| December 31, 2021 | | June 30, 2023 |
| December 31, 2022 | ||||
Oil and natural gas properties and equipment | | $ | 8,780,961 | | $ | 8,636,408 | | $ | 8,847,421 | | $ | 8,813,404 |
Furniture, fixtures and other | |
| 20,827 | |
| 20,844 | |
| 40,224 | |
| 20,915 |
Total property and equipment | |
| 8,801,788 | |
| 8,657,252 | |
| 8,887,645 | |
| 8,834,319 |
Less: Accumulated depreciation, depletion, amortization and impairment | |
| (8,071,830) | |
| (7,992,000) | |
| (8,149,905) | |
| (8,099,104) |
Oil and natural gas properties and other, net | | $ | 729,958 | | $ | 665,252 | | $ | 737,740 | | $ | 735,215 |
6
Other Assets (long-term) – The major categories are presented in the following table (in thousands):
| | | | | | |
| | September 30, 2022 |
| December 31, 2021 | ||
Right-of-Use assets | | $ | 10,443 | | $ | 10,602 |
Investment in White Cap, LLC | |
| 3,193 | |
| 2,533 |
Proportional consolidation of Monza (Note 6) | |
| 15,409 | |
| 2,511 |
Derivatives(1) (Note 8) | |
| 35,656 | |
| 34,435 |
Other | |
| 980 | |
| 1,091 |
Total other assets (long-term) | | $ | 65,681 | | $ | 51,172 |
| | | | | | |
| | June 30, 2023 |
| December 31, 2022 | ||
Right-of-Use assets | | $ | 10,728 | | $ | 10,364 |
Investment in White Cap, LLC | |
| 2,721 | |
| 2,453 |
Proportional consolidation of Monza (Note 6) | |
| 9,909 | |
| 9,321 |
Derivatives(1) (Note 4) | |
| 17,184 | |
| 23,236 |
Other | |
| 1,576 | |
| 2,175 |
Total other assets (long-term) | | $ | 42,118 | | $ | 47,549 |
(1) | Includes open contracts. |
Accrued Liabilities – The major categories are presented in the following table (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 |
| December 31, 2021 | | June 30, 2023 |
| December 31, 2022 | ||||
Accrued interest | | $ | 25,423 | | $ | 10,154 | | $ | 13,848 | | $ | 8,967 |
Accrued salaries/payroll taxes/benefits | |
| 9,711 | |
| 9,617 | |
| 4,808 | |
| 15,097 |
Litigation accruals | |
| 524 | |
| 646 | |
| 56 | |
| 396 |
Lease liability | |
| 1,620 | |
| 1,115 | |
| 1,045 | |
| 1,628 |
Derivatives(1) (Note 8) | |
| 116,008 | |
| 81,456 | ||||||
Derivatives(1) (Note 4) | |
| 18,518 | |
| 46,595 | ||||||
Other | |
| 950 | |
| 3,152 | |
| 1,048 | |
| 1,358 |
Total accrued liabilities | | $ | 154,236 | | $ | 106,140 | | $ | 39,323 | | $ | 74,041 |
(1) | Includes closed contracts which have not yet settled. |
6
Other Liabilities (long-term) – The major categories are presented in the following table (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 |
| December 31, 2021 | | June 30, 2023 |
| December 31, 2022 | ||||
Dispute related to royalty deductions | | $ | 7,564 | | $ | 5,177 | | $ | 5,250 | | $ | 4,937 |
Derivatives (Note 8) | |
| 75,079 | |
| 37,989 | ||||||
Derivatives (Note 4) | |
| 17,417 | |
| 43,061 | ||||||
Lease liability | |
| 10,812 | |
| 11,227 | |
| 11,709 | |
| 10,527 |
Other | |
| 1,386 | |
| 996 | |
| 665 | |
| 609 |
Total other liabilities (long-term) | | $ | 94,841 | | $ | 55,389 | | $ | 35,041 | | $ | 59,134 |
At-the-Market Equity Offering – On March 18, 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100,000,000 of shares of common stock under the Company’s "at-the-market"“at-the-market” equity offering program (the “ATM Program”). The designated sales agents will be entitled to a placement fee of up to 3.0% of the gross sales price per share sold. During the ninesix months ended SeptemberJune 30, 2022,2023, the Company did not sell any shares in connection with the ATM Program.
During the year ended December 31, 2022, the Company sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Program and received proceeds, net of commissions and expenses, of $16.5 million.
7
NOTE 2 — DEBT
The components comprising the Company’s debt are presented in the following table (in thousands):
| | | | | | | | | | | | |
| | June 30, 2023 | | December 31, 2022 | ||||||||
TVPX Loan: | | | | | | | ||||||
Principal | | $ | 11,575 | | $ | — | ||||||
Discount | | | (1,651) | | | | ||||||
Unamortized debt issuance costs | |
| (267) | | | — | ||||||
Total TVPX Loan | |
| 9,657 | | | — | ||||||
| | September 30, 2022 | | December 31, 2021 | | | | | | | ||
Term Loan: | | | | | | | | | | | | |
Principal | | $ | 157,021 | | $ | 190,859 | | | 128,719 | | | 147,899 |
Unamortized debt issuance costs | | | (5,067) | | | (7,545) | | | (3,727) | | | (4,592) |
Total Term Loan | |
| 151,954 | |
| 183,314 | |
| 124,992 | |
| 143,307 |
| | | | | | | | | | | | |
Credit Agreement borrowings: | | | — | | | — | | | — | | | — |
| | | | | | | | | | | | |
Senior Second Lien Notes: | |
| — | |
|
| ||||||
11.75% Senior Second Lien Notes due 2026: | |
| | |
|
| ||||||
Principal | |
| 552,460 | |
| 552,460 | |
| 275,000 | |
| — |
Unamortized debt issuance costs | |
| (2,991) | |
| (4,876) | |
| (6,078) | |
| — |
Total Senior Second Lien Notes | |
| 549,469 | |
| 547,584 | ||||||
Total 11.75% Senior Second Lien Notes due 2026 | |
| 268,922 | |
| — | ||||||
| | | | | | | | | | | | |
Less current portion | | | (35,450) | | | (42,960) | ||||||
9.75% Senior Second Lien Notes due 2023: | |
| | |
|
| ||||||
Principal | |
| — | |
| 552,460 | ||||||
Unamortized debt issuance costs | |
| — | |
| (2,330) | ||||||
Total 9.75% Senior Second Lien Notes due 2023 | |
| — | |
| 550,130 | ||||||
| | | | | | | ||||||
Less current portion, net | | | (30,550) | | | (582,249) | ||||||
Total long-term debt, net | | $ | 665,973 | | $ | 687,938 | | $ | 373,021 | | $ | 111,188 |
7
Current Portion of Long-Term Debt, Net
As of SeptemberJune 30, 2022,2023, the current portion of long-term debt of $35.5$30.6 million represented principal payments due within one year on the TVPX Loan and Term Loan (defined below), net of current unamortized debt issuance costs.
TVPX Loan
On May 15, 2023, the Company acquired a corporate aircraft from a company affiliated with and controlled by W&T’s Chairman, Chief Executive Officer (“CEO”) and President, Tracy W. Krohn. The terms of the transactions were reviewed and approved by the Audit Committee of the Company’s Board of Directors. See Note 12 – Related Party Transactions.
As of September 30, 2022, the Company had outstanding $552.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that mature on November 1, 2023. The Company has commenced discussions with potential lenders and institutional investors regarding a potential refinancing of all or a portionpurchase price of the Senior Second Lien Notes prior to maturity, although there is no assurance as toaircraft was $19.1 million, which was paid using $9.0 million of the terms of any such refinancing or whether or when such refinancing will occur.
The Company believes thatCompany’s cash on hand and cash flows from operations will enablethrough the assumption of an amortizing loan by TVPX Aircraft Solutions Inc. (the “TVPX Loan”), not in its individual capacity but as owner trustee of the trust which holds title to the aircraft, a wholly owned indirect subsidiary of the Company, to satisfy its debt obligations as well as meet its other funding requirementsthe borrower. At the time of the assumption, the TVPX Loan had an aggregate principal amount of approximately $11.8 million outstanding. The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued interest, which began on May 17, 2023, and a balloon payment of $8.0 million at least one year fromthe end of the loan term. The TVPX Loan is guaranteed by the Company on an unsecured basis. Using current market rates, we determined that the fair market value of the TVPX Loan was $10.1 million at the date this Form 10-Q is issued. The Company’s view regarding sufficiency of cash and liquidity is primarily based on the financial forecast, which is impacted by various assumptions including projections for pricing, production volumes and operating costs. Given the assumptions involved, the forecast is subject to uncertainty, therefore cash flows from operations may be lower than projected. assumption.
If necessary, there are further actionsThe aircraft was purchased as part of a series of transactions pursuant to which the Company could undertakerestructured the compensation for its Named Executive Officers. Prior to increase cash flows which include limiting capital expenditures and reducing operating expenditures. Additionally,the Company’s purchase of the aircraft, the Company may seekused the aircraft for business purposes, and the CEO also used the aircraft for personal purposes. Both the Company’s use for business purposes and the CEO’s unlimited use for personal purposes were paid for by the Company pursuant to raise cash through the saleCEO’s prior employment agreement. In connection with the Company’s efforts to significantly reduce overall executive compensation, including perquisite compensation Mr. Krohn was receiving for personal use of upthe aircraft, on April 20, 2023, the Company entered into an amendment to $100the employment agreement with the CEO which requires that the Company be reimbursed for personal use of the aircraft in accordance with the Company’s aircraft use policy.
During the six months ended June 30, 2023, the Company repaid $183.3 thousand of principal outstanding. As of June 30, 2023, the Company had $11.6 million of equity available underprincipal amount outstanding related to the ATM program.TVPX Loan.
8
Term Loan (Subsidiary Credit Agreement)
On May 19, 2021, A-I LLC and A-II LLC (collectively, the “Subsidiary Borrowers”), both Delaware limited liability companies and indirect, wholly-owned subsidiaries of the Company, entered into a credit agreement (the “Subsidiary Credit Agreement”) providing for a term loan (the “Term Loan”) in an aggregate principal amount equal to $215.0 million (the “Term Loan”).million. The Term Loan requires quarterly amortization payments which commenced on September 30, 2021. The Term Loan bears interest at a fixed rate of 7%7.0% per annum and will mature on May 19, 2028. The Subsidiary Credit Agreement required the Company to enter into certain natural gas swap and put derivative contracts. See Note 4 – Derivative Financial Instruments.
In exchange for the net cash proceeds received by the Subsidiary Borrowers from the Term Loan, the Company assigned to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore crude oil treating and sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”).
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The Term Loan is non-recourse to the Company and any subsidiaries other than the Subsidiary Borrowers and the subsidiary that owns the equity in the Subsidiary Borrowers, and is secured by the first lien security interests in the equity of the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers (the Mobile Bay Properties, defined below).
In exchange for the net cash proceeds received by the Subsidiary Borrowers from the Term Loan, the Company assigned to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, in the Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, in the Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore crude oil treating and sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”). A portion of the proceeds to the Company was used to repay the $48.0 million outstanding balance on its reserve-based lending facility under the Credit Agreement (defined below), with the majority of the proceeds to W&T expected to be used for general corporate purposes, including oil and gas acquisitions, development activities, and other opportunities to grow the Company’s broader asset base. The transactions contemplated by the Subsidiary Credit Agreement, including the assignment of the Mobile Bay Properties to A-I LLC and the assignment of the Midstream Assets to A-II LLC are referred to herein as the “Mobile Bay Transaction”. For information about the Mobile Bay Transaction refer to See Note 5 – Subsidiary Borrowers.for additional information.
During the six months ended June 30, 2023, the Company repaid $19.2 million of principal outstanding. As of SeptemberJune 30, 2022 and December 31, 2021,2023, the Company had $157.0 million and $190.9$128.7 million in principal amount of the Term Loan outstanding, respectively.outstanding.
Credit Agreement
On November 2, 2021, theThe Company has entered into the Ninth Amendment to the Sixth Amended and Restateda Credit Agreement (the “Ninth Amendment”), which establishes a short-term $100.0 million first priority lien secured revolving credit facility with borrowings limited to a borrowing base of $50.0 million (the “Credit Agreement”) provided by Calculus Lending, LLC (“Calculus”), a company affiliated with and controlled by W&T’s Chairman, and Chief Executive Officer and President, Tracy W. Krohn, as sole lender under the Credit Agreement. A committeeAgreement (as amended from time to time, the “Credit Agreement”). The Credit Agreement currently has a maturity date of the independent members of the Board of Directors reviewed and approved the amendments given the Chief Executive Officer’s affiliation with Calculus. As of November 2, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate amount of approximately $4.4 million.January 3, 2024. Alter Domus (US) LLC was appointed to replace Toronto Dominion (Texas) LLCserves as the administrative agent under the Credit Agreement.
On March 8, 2022, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”), which extended the maturity date and Calculus’ commitment to January 3, 2023. The terms of this extension with Calculus were reviewed and approved by the Audit Committee of the Company. In connection with the Tenth Amendment, Calculus was paid arrangement and upfront fees of approximately $1.0 million in the aggregate during the nine months ended September 30, 2022.
On November 7, 2022, the Company entered into the Eleventh Amendment to the Credit Agreement (the “Eleventh Amendment”), which extended the maturity date and Calculus’ commitment to January 3, 2024, or in certain circumstances as described in more detail below, to August 1, 2023, and shifted the rate at which outstanding borrowings will accrue interest to a SOFR-based rate. The terms of this extension with Calculus were reviewed and approved by the Audit Committee of the Company.
9
Pursuant to the Eleventh Amendment, the commitment will expire and final maturity of any and all outstanding loans is January 3, 2024, or in the event the Senior Second Lien Notes are not refinanced or replaced in full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023. Outstanding borrowings will accrue interest at SOFR plus 6.0% per annum. The commitment fee for the unused portion of available borrowing amounts will be 3.0% per annum. In connection with the Eleventh Amendment, the Company paid to Calculus an extension fee of $100,000.
As a result of the Ninth Amendment, Tenth Amendment and Eleventh Amendment and related assignments and agreements, the primary terms and covenants associated with the Credit Agreement as of SeptemberJune 30, 2022,2023, are as follows:
● |
|
|
● | Outstanding borrowings accrue interest at SOFR plus 6.0% per annum; |
● | The Company’s ratio of First Lien Debt (as such term is defined in the Credit Agreement) outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX (as such term is defined in the Credit Agreement) for the trailing four quarters must not be greater than 2.50 to 1.00 on the last day of any fiscal quarter commencing with the fiscal quarter ended March 31, 2022; |
● |
| The |
● | The ratio of the Company and |
·The Company’s ratio of First Lien Debt (as such term is defined in the Credit Agreement) outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX (as such term is defined in the Credit Agreement) for the trailing four quarters must not be greater than 2.50 to 1.00 on the last day of the fiscal quarter ending March 31, 2022 and on the last day of each fiscal quarter thereafter;
·The Company’s ratio of Total Proved PV-10 (as such term is defined in the Credit Agreement) to First Lien Debt as of the last day of any fiscal quarter commencing with the fiscal quarter ending March 31, 2022 must be equal to or greater than 2.00 to 1.00;
·The ratio of the Company and its restricted subsidiaries’ consolidated current assets to Company and its restricted subsidiaries’ consolidated current liabilities (subject in each case to certain exceptions and adjustments as set forth in the Credit Agreement) at the last day of any fiscal quarter must be greater than or equal to 1.00 to 1.00;
● | As of the last day of any fiscal quarter commencing with the fiscal quarter |
● | Certain related party transactions are required to meet certain arm’s length criteria; except in each case as specifically permitted or excluded from the covenant under the Credit Agreement. |
In addition, Calculus earned commitment fees of $1,137,500, equal to 3.0% of unborrowed portion of the borrowing base lending commitment, during the nine months ended September 30, 2022.
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Availability under the Credit Agreement is subject to redetermination of the borrowing base that may be requested at the discretion of either the lender or the Company in accordance with the Credit Agreement. The borrowing base is calculated by the lender based on their evaluation of proved reserves and their own internal criteria. Any redetermination by the lender to change the borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement is secured by a first priority lien on substantially all of the Company’s and its guarantor subsidiaries’ assets, excluding those assets of the Subsidiary Borrowers, which liens were released in the Mobile Bay Transaction (as described in Note 5 – Subsidiary Borrowers).
As of SeptemberJune 30, 2022,2023, there were no borrowings outstanding under the Credit Agreement and no borrowings had been incurred under the Credit Agreement during the ninesix months ended SeptemberJune 30, 2022. Separately, as2023. As of SeptemberJune 30, 20222023 and December 31, 2021,2022, the Company had $4.4 million outstanding in letters of credit which have been cash collateralized.
9.75% Senior Second Lien Notes Due 20239
On October 18, 2018, W&T issued $625.0 millionTable of 9.75%Contents
11.75% Senior Second Lien Notes due 2026
On January 27, 2023, (the “Seniorthe Company issued and sold $275 million in aggregate principal amount of its 11.75% Senior Second Lien Notes”), which were issuedNotes at par with an interest rate of 9.75%11.75% per annum and maturethat matures on NovemberFebruary 1, 2023, and2026 (the “11.75% Senior Second Lien Notes”), which are governed under the terms of the Indenture of the Senior Second Lien Notesan indenture (the “Indenture”). The estimated annual effective interest rateInterest on the Senior Second Lien Notes is 10.3%, which includes amortization of debt issuance costs. Interest on the11.75% Senior Second Lien Notes is payable in arrears on MayFebruary 1 and NovemberAugust 1, of each year. As of September 30, 2022 and December 31, 2021, $552.5 million in principal amount ofcommencing August 1, 2023. The 11.75% Senior Second Lien Notes remained issuedwill be recorded at their carrying value consisting of principal and outstanding.
unamortized debt issuance costs. The 11.75% Senior Second Lien Notes are secured by a second-priority lienliens on all of the Company’s assetssame collateral that areis secured under the Credit Agreement, which does not include the Mobile Bay Properties and the related Midstream Assets. The estimated annual effective interest rate on the 11.75% Senior Second Lien Notes is 12.6%, which includes amortization of deferred interest costs.
Prior to August 1, 2024, the Company may redeem all or any portion of the 11.75% Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the notes outstanding plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to August 1, 2024, the Company may, at its option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the 11.75% Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 111.750% of the principal amount of the outstanding plus accrued and unpaid interest, if any, to the redemption date.
On and after August 1, 2024, the Company may redeem the 11.75% Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 105.875% for the 12-month period beginning August 1, 2024, and 100.000% on August 1, 2025 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The 11.75% Senior Second Lien Notes are guaranteed by the Guarantors.
The 11.75% Senior Second Lien Notes contain covenants that limit or prohibit the Company’s ability and the ability of certain of its subsidiaries to: (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture. These covenants are subject to important exceptions and qualifications set forth in the Indenture. In addition, most of the above describedabove-described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the 11.75% Senior Second Lien Notes an investment grade rating and no default exists with respect to the 11.75% Senior Second Lien Notes.
Redemption of 9.75% Senior Second Lien Notes due 2023
On October 18, 2018, the Company issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “9.75% Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and would have matured on November 1, 2023.
On February 8, 2023, the Company redeemed all of the $552.5 million of aggregate principle outstanding of the 9.75% Senior Second Lien Notes at a redemption price of 100.0%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes and cash on hand of $296.1 million to fund the redemption.
Covenants
As of SeptemberJune 30, 20222023 and for all prior measurement periods presented, the Company was in compliance with all applicable covenants of the Credit Agreement and the Indenture.
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NOTE 3 – FAIR VALUE MEASUREMENTS
Derivative Financial Instruments
Derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 4 – Derivative Financial Instruments for additional information on derivative financial instruments. The Company measures the fair value of derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The income approach converts expected future cash flows to a present value amount based on market expectations. The inputs used for the fair value measurement of derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. Derivative
The following table presents the fair value of the Company’s derivative financial instruments are reported(in thousands):
| | | | | | |
| | June 30, 2023 |
| December 31, 2022 | ||
Assets: |
| |
|
| |
|
Derivative instruments - current | | $ | 1,778 | | $ | 4,954 |
Derivative instruments - long-term | |
| 17,184 | |
| 23,236 |
| | | | | | |
Liabilities: | |
|
| |
|
|
Derivative instruments - current | |
| 18,518 | |
| 46,595 |
Derivative instruments - long-term | |
| 17,417 | |
| 43,061 |
Debt Instruments
The following table presents the net value and fair value of the Company’s debt (in thousands):
| | | | | | | | | | | | |
|
| June 30, 2023 |
| December 31, 2022 | ||||||||
| | Net Value |
| Fair Value |
| Net Value |
| Fair Value | ||||
Liabilities: |
| |
|
| |
|
| |
|
| |
|
TVPX Loan | | $ | 9,657 | | $ | 9,977 | | $ | — | | $ | — |
Term Loan | | | 124,992 | | | 120,965 | | | 143,307 | | | 139,056 |
11.75% Senior Second Lien Notes due 2026 | | | 268,922 | |
| 275,303 | |
| — | |
| — |
9.75% Senior Second Lien Notes due 2023 | |
| — | |
| — | |
| 550,130 | |
| 544,902 |
Total | | $ | 403,571 | | $ | 406,245 | | $ | 693,437 | | $ | 683,958 |
The fair value of the TVPX Loan and the Term Loan were measured using a discounted cash flows model and current market rates. The fair value of the 11.75% Senior Second Lien Notes and 9.75% Senior Second Lien Notes were measured using quoted prices, although the market is not a highly liquid market. The fair value of debt was classified as Level 2 within the valuation hierarchy.
NOTE 4 — DERIVATIVE FINANCIAL INSTRUMENTS
W&T’s market risk exposure relates primarily to commodity prices. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps, costless collars, sold calls and purchased puts. The Company is exposed to credit loss in the Condensed Consolidated Balance Sheets using fair value. See Note 8 – Derivative Financial Instruments, forevent of nonperformance by the derivative counterparties; however, the Company currently anticipates that the derivative counterparties will be able to fulfill their contractual obligations. The Company is not required to provide additional information oncollateral to the derivative financial instruments.counterparties and does not require collateral from the derivative counterparties.
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W&T has elected not to designate commodity derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as Derivative (gain) losson the Condensed Consolidated Statements of Operations in each period presented. The cash flows of all commodity derivative contracts are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.
The natural gas contracts are based off the Henry Hub prices, which is quoted off the New York Mercantile Exchange (“NYMEX”).
The following table presentsreflects the fair valuecontracted volumes and weighted average prices under the terms of the Company’s open derivative financial instruments (in thousands):contracts as of June 30, 2023:
| | | | | | |
| | September 30, 2022 |
| December 31, 2021 | ||
Assets: |
| |
|
| |
|
Derivative instruments - current | | $ | 28,747 | | $ | 21,086 |
Derivative instruments - long-term | |
| 35,656 | |
| 34,435 |
| | | | | | |
Liabilities: | |
|
| |
|
|
Derivative instruments - current | |
| 116,008 | |
| 81,456 |
Derivative instruments - long-term | |
| 75,079 | |
| 37,989 |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Average | | | | | | | | | | | |
| | Instrument | | Daily | | Total | | Weighted | | Weighted | | Weighted | |||
Period |
| Type |
| Volumes |
| Volumes |
| Strike Price |
| Put Price |
| Call Price | |||
| | | | | | | | | | | | | | | |
Natural Gas - Henry Hub (NYMEX) | | (MMbtu)(1) | | (MMbtu)(1) | | | ($/MMbtu)(1) | | | ($/MMbtu)(1) | | | ($/MMbtu)(1) | ||
July 2023 - Dec 2023 | | calls | | 35,288 | | 12,880,000 | | $ | — | | $ | — | | $ | 7.50 |
Jan 2024 - Dec 2024 | | calls | | 65,000 | | 23,790,000 | | $ | — | | $ | — | | $ | 6.13 |
Jan 2025 - Mar 2025 | | calls | | 62,000 | | 5,580,000 | | $ | — | | $ | — | | $ | 5.50 |
July 2023 - Dec 2023(2) | | swaps | | 36,164 | | 13,200,000 | | $ | 2.43 | | $ | — | | $ | — |
Jan 2024 - Dec 2024(2) | | swaps | | 65,574 | | 24,000,000 | | $ | 2.46 | | $ | — | | $ | — |
Jan 2025 - Mar 2025(2) | | swaps | | 63,333 | | 5,700,000 | | $ | 2.72 | | $ | — | | $ | — |
Apr 2025 - Dec 2025(2) | | puts | | 62,182 | | 17,100,000 | | $ | — | | $ | 2.27 | | $ | — |
Jan 2026 - Dec 2026(2) | | puts | | 55,890 | | 20,400,000 | | $ | — | | $ | 2.35 | | $ | — |
Jan 2027 - Dec 2027(2) | | puts | | 52,603 | | 19,200,000 | | $ | — | | $ | 2.37 | | $ | — |
Jan 2028 - Apr 2028(2) | | puts | | 49,587 | | 6,000,000 | | $ | — | | $ | 2.50 | | $ | — |
Debt Instruments
(1) | MMbtu – Million British Thermal Units |
(2) | These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with the Term Loan (see Note 5 – Subsidiary Borrowers). |
Financial Statement Presentation
The following table presents the net value and fair value of derivative financial instruments amounts were recorded in the Company’s debtCondensed Consolidated Balance Sheets (in thousands):
| | | | | | | | | | | | |
|
| September 30, 2022 |
| December 31, 2021 | ||||||||
| | Net Value |
| Fair Value |
| Net Value |
| Fair Value | ||||
Liabilities: |
| |
|
| |
|
| |
|
| |
|
Term Loan | | $ | 151,954 | | $ | 147,137 | | $ | 183,314 | | $ | 190,579 |
Senior Second Lien Notes | |
| 549,469 | |
| 543,206 | |
| 547,584 | |
| 527,715 |
Total | | $ | 701,423 | | $ | 690,343 | | $ | 730,898 | | $ | 718,294 |
| | | | | | |
|
| June 30, 2023 |
| December 31, 2022 | ||
Prepaid expenses and other current assets | | $ | 1,778 | | $ | 4,954 |
Other assets (long-term) | |
| 17,184 | |
| 23,236 |
Accrued liabilities | |
| 18,518 | |
| 46,595 |
Other liabilities (long-term) | | | 17,417 | | | 43,061 |
The fair value of the Term Loan was measured using a discounted cash flows model and current market rates. The fair value of the Senior Second Lien Notes was measured using quoted prices, although the market is not a highly liquid market. The fair value of debt was classified as Level 2 within the valuation hierarchy.
NOTE 4 — ACQUISITIONS
On January 5, 2022,Although the Company entered intohas master netting arrangements with its counterparties, the amounts recorded on the Condensed Consolidated Balance Sheets are on a purchase and sale agreement with ANKOR E&P Holdings Corporation and KOA Energy LP (“ANKOR”) to acquire their interests in and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields for $47.0 million. The transaction closed on February 1, 2022, and after normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date of July 1, 2021 to the close date), cash consideration of $34.0 million was paid to the sellers. The transaction was funded using cash on hand. The Company also assumed the related asset retirement obligations (“ARO”) associated with these assets.
Additionally, on April 1, 2022, the Company entered into a purchase and sale agreement with a private seller to acquire the remaining working interests in certain oil and natural gas producing properties in federal shallow waters of the Gulf of Mexico at the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields purchased from ANKOR. The transaction had an effective date and closing date of April 1, 2022.After normal and customary post-effective date adjustments, cash consideration of $17.5 million was paid to the seller.gross basis.
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The Company determined that the assets acquired did not meet the definition of a business; therefore, the transactions were accounted for as asset acquisitions in accordance with ASC 805. An acquisition qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Condensed Consolidated Balance Sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurementsChanges in the fair value hierarchy and include, butsettlements of contracts are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired. The amounts recorded on the Condensed Consolidated Balance Sheet forStatements of Operations as Derivative (gain) loss, net. The impact of commodity derivative contracts on the purchase price allocation and liabilities assumed related to the acquisitions described above on February 1, 2022, and April 1, 2022, are presented in the following tables, respectivelyCondensed Consolidated Statements of Operations were as follows (in thousands):
| | | |
|
| February 1, | |
Oil and natural gas properties and other, net | | $ | 54,299 |
Restricted deposits for asset retirement obligations | |
| 6,196 |
Asset retirement obligations | |
| (26,493) |
Allocated purchase price | | $ | 34,002 |
| | | |
| | April 1, | |
|
| 2022 | |
Oil and natural gas properties and other, net | | $ | 22,632 |
Restricted deposits for asset retirement obligations | |
| 1,549 |
Asset retirement obligations | |
| (6,709) |
Allocated purchase price | | $ | 17,472 |
| | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||
|
| 2023 |
| 2022 |
| 2023 |
| 2022 | ||||
Realized loss (gain)(1) | | $ | 300 | | $ | (79,667) | | $ | 530 | | $ | (35,973) |
Unrealized (gain) loss | | | (1,129) | | | 70,813 | | | (40,599) | | | 107,116 |
Derivative (gain) loss, net | | $ | (829) | | $ | (8,854) | | $ | (40,069) | | $ | 71,143 |
(1) | The three and six months ended June 30, 2022 includes the effect of the $138.0 million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices. |
Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows and were as follows (in thousands):
| | | | | | |
| | Six Months Ended June 30, | ||||
|
| 2023 |
| 2022 | ||
Derivative (gain) loss, net | | $ | (40,069) | | $ | 71,143 |
Derivative cash (receipts) payments, net(1) | | | (4,427) | | | 70,227 |
Derivative cash premium payments, net | | | — | | | (46,111) |
(1) | The six months ended June 30, 2022 includes $105.3 million of net cash receipts related to the monetization of certain natural gas call contracts through restructuring of strike prices. |
NOTE 5 — SUBSIDIARY BORROWERS
On May 19, 2021, the Company’s wholly-owned special purpose vehicles (the “SPVs”), the Subsidiary Borrowers, entered into the Subsidiary Credit Agreement providing for the Term Loan in an aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Subsidiary Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts described in more detail under Note 84 – Derivative Financial Instruments, of this Quarterly Report on Form 10-Q (this “Quarterly Report”).10-Q.
As partThe Subsidiary Borrowers are wholly-owned subsidiaries of the Mobile Bay Transaction,Company; however, the SPVs entered into a management services agreement (the “Services Agreement”) withassets of the Company, pursuantSubsidiary Borrowers are not available to whichsatisfy the Company will provide (a) certain operational and management services for (i) the Mobile Bay Properties and (ii) the Midstream Assets and (b) certain corporate, general and administrative services for A-I LLC and A-II LLC (collectively in this capacity, the “Services Recipient”). Under the Services Agreement, the Company will indemnify the Services Recipient with respect to claims, lossesdebt or liabilities incurred by the Services Agreement parties that relate to personal injurycontractual obligations of any other entities, including debt securities or death or property damageother contractual obligations of the Company, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Services Recipient. The Services Recipient will indemnify the Company with respect to claims, losses or liabilities incurred by the Company that relate to personal injury or death of the Services Recipient or property damage of the Services Recipient, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Company. The Services Agreement will terminate upon the earlier of (a) termination ofand the Subsidiary Credit AgreementBorrowers do not bear any liability for the indebtedness or other contractual obligations of any other entities, and payment and satisfaction of all obligations thereunder or (b)vice versa.
During the exercise of certain remedies by the secured parties underyear ended December 31, 2022, the Subsidiary Credit Agreement andBorrowers paid cash distributions to W&T of $30.2 million. During the realization bysix months ended June 30, 2023, no such secured parties upon any of the collateral under the Subsidiary Credit Agreement.distributions were paid.
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The SPVs are wholly-owned subsidiaries of the Company; however, the assets of the SPVs will not be available to satisfy the debt or contractual obligations of any non-SPV entities, including debt securities or other contractual obligations of the Company, and the SPVs do not bear any liability for the indebtedness or other contractual obligations of any non-SPVs, and vice versa.
Consolidation and Carrying Amounts
The following table presents the amounts recorded by W&T on the Condensed Consolidated Balance Sheets related to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 | | December 31, 2021 | | June 30, 2023 | | December 31, 2022 | ||||
Assets: |
| |
|
| |
|
| |
|
| |
|
Cash and cash equivalents | | $ | 54,219 | | $ | 38,937 | | $ | 5,899 | | $ | 21,764 |
Receivables: | |
|
| |
|
| |
|
| |
|
|
Oil and natural gas sales | |
| 80,431 | |
| 34,420 | |
| 18,411 | |
| 37,344 |
Joint interest, net | |
| (5,749) | |
| (10,856) | |
| (27,400) | |
| (5,760) |
Prepaid expenses and other assets | |
| 614 | |
| 356 | |
| 125 | |
| 417 |
Oil and natural gas properties and other, net | |
| 280,444 | |
| 272,747 | |
| 289,959 | |
| 280,649 |
Other assets | |
| (19,438) | |
| (19,903) | |
| 11,486 | |
| 8,473 |
Liabilities: | |
|
| |
|
| |
|
| |
|
|
Accounts payable | | | 49,859 | | | 29,678 | | | 8,996 | | | 27,387 |
Undistributed oil and natural gas proceeds | |
| 22,077 | |
| 3,144 | |
| 3,625 | |
| 7,930 |
Accrued liabilities | |
| 89,431 | |
| 29,937 | |
| 19,036 | |
| 45,102 |
Current portion of long-term debt | | | 35,450 | | | 42,960 | | | 30,074 | | | 32,119 |
Long-term debt, net | |
| 116,504 | |
| 140,353 | |
| 94,918 | |
| 111,188 |
Asset retirement obligations | |
| 59,107 | |
| 54,515 | |
| 66,136 | |
| 61,138 |
Other liabilities | |
| 79,602 | |
| 42,615 | |
| 22,020 | |
| 47,398 |
The following table presents the amounts recorded by W&T in the Condensed Consolidated Statement of Operations related to the consolidation of the operations of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers (in thousands):
| | | | | | | ||||||||||||
| | | | | The period from | | | | | | | | | | | | | |
| | Nine Months Ended | | May 19, 2021 to | | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||||
| | September 30, 2022 | | September 30, 2021 | | 2023 | | 2022 | | 2023 | | 2022 | ||||||
Total revenues | | $ | 218,625 | | $ | 63,053 | | $ | 25,437 | | $ | 76,846 | | $ | 46,560 | | $ | 124,361 |
Total operating expenses | |
| 52,961 | |
| 26,644 | |
| 30,443 | |
| 18,385 | |
| 50,490 | |
| 33,185 |
Interest expense, net | |
| 11,841 | |
| 5,930 | |
| 3,229 | |
| 3,658 | |
| 5,411 | |
| 8,436 |
Derivative loss | |
| 187,896 | |
| 124,364 | ||||||||||||
Other income | | | 64 | | | — | ||||||||||||
Derivative (gain) loss, net | |
| (6,012) | |
| 35,888 | |
| (52,389) | |
| 132,046 |
14
NOTE 6 — JOINT VENTURE DRILLING PROGRAM
In March 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with the Company in the exploration, drilling and development of certain drilling projects (the “Joint Venture Drilling Program”) in the Gulf of Mexico. Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T’s commitment to fund its retained interest in Monza projects held outside of Monza, was $361.4 million. W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that W&T initially receives an aggregate of 30.0% of the revenues less expenses, through the direct ownership from the retained working interest in the Monza projects and the Company’s indirect interest through theits interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board of directors.
14
The members of Monza are third-party investors, W&T and an entity owned and controlled by Mr. Tracy W. Krohn, ourthe Company’s Chairman, and Chief Executive Officer.Officer and President. The Krohn entity affiliated with the Company’s CEO invested as a minority investor on the same terms and conditions as the third-party investors, and its investment is limited to 4.5% of total invested capital within Monza. The entity affiliated with Mr. KrohnMonza, and made a capital commitment to Monza of $14.5 million.
Monza is an entity separate from any other entity with its own separate creditors who will be entitled, upon its liquidation, to be satisfied out of Monza’s assets prior to any value in Monza becoming available to holders of its equity. The assets of Monza are not available to pay creditors of the Company and its affiliates.
Through SeptemberJune 30, 2022,2023, ten wells have been completed since the inception of the Joint Venture Drilling Program. W&T is the operator for eight of the ten wells completed through SeptemberJune 30, 2022.2023.
Through SeptemberSince inception through June 30, 2022,2023, members of Monza made partner capital contributions, including W&T’s contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling $138.4$204.7 million. Through SeptemberSince inception through June 30, 2022,2023, W&T made total capital contributions, including the contributions of working interest in the drilling projects, to Monza totaling $68.2 million and received cash distributions totaling $31.8$48.3 million.
Consolidation and Carrying Amounts
W&T’s interest in Monza is considered to be a variable interest that is proportionally consolidated. Through SeptemberJune 30, 2022,2023, there have been no events or changes that would cause a redetermination of the variable interest status. W&T does not fully consolidate Monza because the Company is not considered the primary beneficiary of Monza.
The following table presents the amounts recorded by W&T on the Condensed Consolidated Balance Sheets related to the consolidation of the proportional interest in Monza’s operations (in thousands):
| | | | | | | | | | | | |
| | September 30, 2022 | | December 31, 2021 | | June 30, 2023 | | December 31, 2022 | ||||
Working capital | | $ | 3,583 | | $ | 4,648 | | $ | 1,191 | | $ | 2,515 |
Oil and natural gas properties and other, net | |
| 39,131 | |
| 45,510 | |
| 34,516 | |
| 37,260 |
Asset retirement obligations | | | 432 | | | 375 | | | 518 | | | 467 |
Other assets | |
| 15,409 | |
| 2,511 | |
| 9,909 | |
| 11,571 |
Other liabilities | | | 2,627 | | | — |
Additionally, during the year ended December 31, 2021,As required, W&T calledmay call on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of SeptemberJune 30, 20222023 and December 31, 20212022 were $2.9$2.8 million and $14.8$2.9 million, respectively, which are included in the Condensed Consolidated Balance Sheets in Advances from joint interest partners.
15
The following table presents the amounts recorded by W&T in the Condensed Consolidated Statement of Operations related to the consolidation of the proportional interest in Monza’s operations (in thousands):
| | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Six Months Ended June 30, | ||||||||
| | 2022 | | 2021 | | 2023 | | 2022 | ||||
Total revenues | | $ | 23,681 | | $ | 8,730 | | $ | 6,018 | | $ | 16,615 |
Total operating expenses | |
| 10,805 | |
| 7,564 | |
| 4,623 | |
| 7,368 |
Derivative loss | |
| — | |
| 1,966 | ||||||
Interest income | |
| 104 | |
| — |
15
NOTE 7 — ASSET RETIREMENT OBLIGATIONS
AROs represent the estimated present value of the amount incurred to plug, abandon and remediate ourthe Company’s properties at the end of their productive lives. A summary of the changes to ARO is as follows (in thousands):
| | | | | | |
| | Nine Months Ended September 30, | | Six Months Ended June 30, | ||
|
| 2022 |
| 2023 | ||
Asset retirement obligations, beginning of period | | $ | 424,495 | | $ | 466,430 |
Liabilities settled | |
| (61,285) | |
| (11,841) |
Accretion expense | |
| 19,536 | |
| 15,227 |
Liabilities acquired | |
| 33,202 | |||
Liabilities incurred | | | 138 | | | 113 |
Revisions of estimated liabilities | |
| 37,524 | |
| 10,903 |
Asset retirement obligations, end of period | | | 453,610 | | | 480,832 |
Less: Current portion | |
| (54,886) | |
| (37,763) |
Long-term | | $ | 398,724 | | $ | 443,069 |
NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS SHARE-BASED AWARDS AND CASH BASED AWARDS
W&T’s market risk exposure relates primarily to commodity prices. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production throughOn June 16, 2023, the use of oil and natural gas swaps, costless collars, sold calls and purchased puts. The Company is exposed to credit loss in the event of nonperformance2023 Incentive Compensation Plan (the “2023 Plan”) was approved by the derivative counterparties; however,Company’s shareholders. The 2023 Plan is effective June 16, 2023, and the Company currently anticipates that the derivative counterparties will be able to fulfill their contractual obligations. The Company is not required to provide additional collateralno longer grant awards pursuant to the derivative counterpartiesW&T Offshore, Inc. Amended and does not require collateralRestated Incentive Compensation Plan, as amended from time to time, (the “Prior Plan”) or the derivative counterparties.2004 Directors Compensation Plan, as amended from time to time. Under the 2023 Plan, the Company may issue, subject to the approval of the Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards, dividend equivalents, other stock-based awards, performance units or shares, cash awards, substitute awards or any combination of the foregoing to eligible employees, non-employee directors, and consultants. Any awards granted prior to the effective date of the 2023 Plan are considered to have been granted under the Prior Plan.
W&T has elected notShare-Based Awards to designate commodity derivative contracts for hedge accounting. Employees
Accordingly, commodity derivativesRestricted Stock Units (“RSUs”) – On June 5, 2023, the Company granted RSUs under the Prior Plan to certain employees. RSUs outstanding as of June 30, 2023 relate to the 2023, 2022, and 2021 grants. The 2023 RSUs granted are recordeda long-term compensation component, subject to service conditions, with one-third of the award vesting each year on June 5, 2024, 2025 and 2026, respectively.
A summary of activity related to RSUs during the Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes insix months ended June 30, 2023 is as follows:
| | | | | |
| | | | Weighted | |
|
| |
| Average | |
| | Restricted | | Grant Date Fair | |
| | Stock Units | | Value Per Unit | |
Nonvested, beginning of period | | 1,221,461 | | $ | 5.76 |
Granted |
| 1,527,221 | |
| 4.09 |
Vested |
| (486,134) | |
| 5.62 |
Forfeited |
| (80,911) | |
| 5.97 |
Nonvested, end of period |
| 2,181,637 | | | 4.61 |
Performance Share Units (“PSUs”) – On June 5, 2023, the unrealized fair value, recorded asCompany granted PSUs under the Prior Plan Derivative (gain) losson the Condensed Consolidated Statements of Operations in each period presented. The cash flows of all commodity derivative contractsthat are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.
The crude oil contracts areeligible to vest based on West Texas Intermediate (“WTI”) crude oil pricescontinued employment and the natural gas contracts are based offCompany’s total shareholder return (“TSR”) ranking against peer companies’ TSR over a three-year performance period, which ends on December 31, 2025. PSUs outstanding as of June 30, 2023 relate to the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).2023, 2022 and 2021 grants.
16
The following table reflectsA summary of activity related to PSUs during the contracted volumes and weighted average prices under the terms of the Company’s open derivative contractssix months ended June 30, 2023 is as of September 30, 2022:follows:
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Average | | | | | | | | | | | |
| | Instrument | | Daily | | Total | | Weighted | | Weighted | | Weighted | |||
Period |
| Type |
| Volumes |
| Volumes |
| Strike Price |
| Put Price |
| Call Price | |||
| | | | | | | | | | | | | | | |
Crude Oil - WTI (NYMEX) | | (Bbls)(1) | | (Bbls)(1) | | | ($/Bbls)(1) | | | ($/Bbls)(1) | | | ($/Bbls)(1) | ||
Jul 2022 - Nov 2022 | | swaps | | 2,174 | | 132,612 | | $ | 58.38 | | $ | — | | $ | — |
Jul 2022 - Nov 2022 |
| collars |
| 2,174 |
| 132,612 |
| $ | — |
| $ | 46.00 |
| $ | 66.40 |
| | | | | | | | | | | | | | | |
Natural Gas - Henry Hub (NYMEX) | | (MMbtu)(2) | | (MMbtu)(2) | | | ($/MMbtu)(2) | | | ($/MMbtu)(2) | | | ($/MMbtu)(2) | ||
Jul 2022 - Dec 2022 | | calls | | 108,647 | | 9,995,479 | | $ | — | | $ | — | | $ | 7.42 |
Jan 2023 - Dec 2023 | | calls | | 70,000 | | 25,550,000 | | $ | — | | $ | — | | $ | 7.50 |
Jan 2024 - Dec 2024 | | calls | | 65,000 | | 23,790,000 | | $ | — | | $ | — | | $ | 6.13 |
Jan 2025 - Mar 2025 | | calls | | 62,000 | | 5,580,000 | | $ | — | | $ | — | | $ | 5.50 |
Jul 2022 - Dec 2022 | | collars | | 40,000 | | 3,680,000 | | $ | — | | $ | 1.83 | | $ | 3.00 |
Jul 2022 - Nov 2022 | | swaps | | 16,838 | | 1,027,099 | | $ | 2.60 | | $ | — | | $ | — |
Jul 2022 - Dec 2022(3) | | swaps | | 78,261 | | 7,200,000 | | $ | 2.63 | | $ | — | | $ | — |
Jan 2023 - Dec 2023(3) | | swaps | | 72,329 | | 26,400,000 | | $ | 2.48 | | $ | — | | $ | — |
Jan 2024 - Dec 2024(3) | | swaps | | 65,574 | | 24,000,000 | | $ | 2.46 | | $ | — | | $ | — |
Jan 2025 - Mar 2025(3) | | swaps | | 63,333 | | 5,700,000 | | $ | 2.72 | | $ | — | | $ | — |
Apr 2025 - Dec 2025(3) | | puts | | 62,182 | | 17,100,000 | | $ | — | | $ | 2.27 | | $ | — |
Jan 2026 - Dec 2026(3) | | puts | | 55,890 | | 20,400,000 | | $ | — | | $ | 2.35 | | $ | — |
Jan 2027 - Dec 2027(3) | | puts | | 52,603 | | 19,200,000 | | $ | — | | $ | 2.37 | | $ | — |
Jan 2028 - Apr 2028(3) | | puts | | 49,587 | | 6,000,000 | | $ | — | | $ | 2.50 | | $ | — |
|
|
|
|
|
|
Financial Statement Presentation
The following fair value of derivative financial instruments amounts were recorded in the Condensed Consolidated Balance Sheets (in thousands):
| | | | | | |
|
| September 30, 2022 |
| December 31, 2021 | ||
Prepaid expenses and other current assets | | $ | 28,747 | | $ | 21,086 |
Other assets (long-term) | |
| 35,656 | |
| 34,435 |
Accrued liabilities | |
| 116,008 | |
| 81,456 |
Other liabilities (long-term) | | | 75,079 | | | 37,989 |
| | | | | |
| | | | Weighted | |
|
| |
| Average | |
| | Performance | | Grant Date Fair | |
| | Share Units | | Value Per Unit | |
Nonvested, beginning of period | | 1,502,239 | | $ | 9.78 |
Granted |
| 1,187,638 | |
| 4.87 |
Vested |
| (10,705) | |
| 7.80 |
Forfeited |
| (188,307) | |
| 10.05 |
Nonvested, end of period |
| 2,490,865 | | | 7.43 |
The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted at the date indicated:
| | | | |
| | 2023 Grant Date | ||
| | June 5, 2023 | ||
Expected term for performance period (in years) | | | 2.6 | |
Expected volatility | | | 76.1 | % |
Risk-free interest rate | | | 4.2 | % |
Fair value (in thousands) | | $ | 5,694 | |
Share-Based Awards to Non-Employee Directors
The Company may from time-to-time issue awards to non-employee directors pursuant to the 2023 Plan. There were no awards granted to non-employee directors during the six months ended June 30, 2023. Restricted shares vested during the six months ended June 30, 2023 relate to 2022 restricted shares issued to the non-employee directors.
A summary of activity related to restricted shares during the six months ended June 30, 2023 is as follows:
| | | | | |
| | | | Weighted | |
| | | | Average | |
| | | | Grant Date | |
|
| Restricted |
| Fair Value | |
| | Shares | | Per Share | |
Nonvested, beginning of period | | 42,426 | | $ | 4.95 |
Vested |
| (42,426) | |
| 4.95 |
Nonvested, end of period |
| — | | $ | — |
Share-Based Compensation Expense
Compensation costs for share-based payments are recognized over the requisite service period. A summary of compensation expense under share-based payment arrangements is as follows (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||
|
| 2023 |
| 2022 |
| 2023 |
| 2022 | ||||
Restricted stock units | | $ | 945 | | $ | 1,360 | | $ | 1,443 | | $ | 1,610 |
Performance share units | | | 1,124 | | | 598 | | | 2,496 | | | 803 |
Restricted Shares | |
| 18 | |
| 56 | |
| 70 | |
| 121 |
Total | | $ | 2,087 | | $ | 2,014 | | $ | 4,009 | | $ | 2,534 |
Cash-Based Incentive Compensation
In addition to share-based compensation, short-term cash-based incentive awards were granted under the Plan to all eligible employees during the six months ended June 30, 2023. The short-term cash-based incentive awards granted in 2022 were paid in March 2023.
17
Although the Company has master netting arrangements with its counterparties, the amounts recorded on the Condensed Consolidated Balance Sheets are on a gross basis.
Changes in the fair value and settlements of contracts are recorded on the Condensed Consolidated Statements of Operations as Derivative (gain) loss. The impact of commodity derivative contracts on the Condensed Consolidated Statements of Operations were as follows (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | ||||||||
|
| 2022 |
| 2021 |
| 2022 |
| 2021 | ||||
Realized loss(1) | | $ | 132,289 | | $ | 30,026 | | $ | 96,315 | | $ | 53,627 |
Unrealized (gain) loss | | | (93,540) | | | 43,111 | | | 13,577 | | | 125,529 |
Derivative loss | | $ | 38,749 | | $ | 73,137 | | $ | 109,892 | | $ | 179,156 |
Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows and were as follows (in thousands):
| | | | | | |
| | Nine Months Ended September 30, | ||||
|
| 2022 |
| 2021 | ||
Derivative loss | | $ | 109,892 | | $ | 179,156 |
Derivative cash (payments) receipts, net(1) | | | (1,022) | | | (39,554) |
Derivative cash premium payments | | | (46,111) | | | (32,368) |
NOTE 9 — SHARE-BASED AWARDS AND CASH BASED AWARDS
The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by the Company’s shareholders in 2010. Under the Plan, the Company may issue, subject to the approval of the Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, performance units or shares, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants.
Share-Based Awards to Employees
Restricted Stock Units (“RSUs”) – During the nine months ended September 30, 2022, the Company granted RSUs under the Plan to certain employees. RSUs outstanding as of September 30, 2022 relate to the 2022 and 2021 grants. The 2022 RSUs granted are a long-term compensation component, subject to service conditions, with one-third of the award vesting each year on January 1, 2023, 2024, and 2025, respectively.
18
A summary of activity related to RSUs during the nine months ended September 30, 2022 is as follows:
| | | | | |
| | | | Weighted | |
|
| |
| Average | |
| | Restricted | | Grant Date Fair | |
| | Stock Units | | Value Per Unit | |
Nonvested, beginning of period | | 698,465 | | $ | 4.71 |
Granted |
| 977,681 | |
| 6.24 |
Vested(1) |
| (387,285) | |
| 5.20 |
Forfeited |
| (66,984) | |
| 5.16 |
Nonvested, end of period |
| 1,221,877 | | | 5.75 |
Performance Share Units (“PSUs”) – During the nine months ended September 30, 2022, the Company granted PSUs under the Plan that are eligible to vest based on continued employment and the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR over a three-year performance period, which ends on December 31, 2024.
The 2021 grants were subject to performance criteria against the applicable performance period, which ended on December 31, 2021. The PSUs granted during 2021 are eligible to vest based on continued employment through October 1, 2023.
A summary of activity related to PSUs during the nine months ended September 30, 2022 is as follows:
| | | | | |
| | | | Weighted | |
|
| |
| Average | |
| | Performance | | Grant Date Fair | |
| | Share Units | | Value Per Unit | |
Nonvested, beginning of period | | 196,918 | | $ | 5.55 |
Granted |
| 1,377,501 | |
| 10.28 |
Vested (1) |
| (15,264) | |
| 5.57 |
Forfeited |
| (57,065) | |
| 8.72 |
Nonvested, end of period |
| 1,502,090 | | | 9.77 |
The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted at the date indicated:
| | | | |
| | May 26, 2022 | ||
Expected term for performance period (in years) | | | 2.6 | |
Expected volatility | | | 84.4 | % |
Risk-free interest rate | | | 2.5 | % |
Fair value (in thousands) | | $ | 14,163 | |
Share-Based Awards to Non-Employee Directors
During the nine months ended September 30, 2022, the Company granted Restricted Shares under the W&T Offshore, Inc. 2004 Directors Compensation Plan to non-employee directors. The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless otherwise approved by the Board of Directors.
19
A summary of activity related to Restricted Shares during the nine months ended September 30, 2022 is as follows:
| | | | | |
| | | | Weighted | |
| | | | Average | |
| | | | Grant Date | |
|
| Restricted |
| Fair Value | |
| | Shares | | Per Share | |
Nonvested, beginning of period | | 70,226 | | $ | 3.65 |
Granted |
| 42,426 | |
| 4.95 |
Vested |
| (70,226) | |
| 3.65 |
Nonvested, end of period |
| 42,426 | | $ | 4.95 |
Share-Based Compensation Expense
Compensation costs for share-based payments is recognized over the requisite service period. A summary of compensation expense under share-based payment arrangements is as follows (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | ||||||||
|
| 2022 |
| 2021 |
| 2022 |
| 2021 | ||||
Restricted stock units | | $ | 1,240 | | $ | 587 | | $ | 2,852 | | $ | 1,263 |
Performance share units | | | 1,352 | | | 207 | | | 2,154 | | | 207 |
Restricted Shares | |
| 53 | |
| 64 | |
| 173 | |
| 309 |
Total | | $ | 2,645 | | $ | 858 | | $ | 5,179 | | $ | 1,779 |
Cash-Based Incentive Compensation
In addition to share-based compensation, short-term cash-based incentive awards were granted under the Plan to all eligible employees during the second quarter of 2022 subject to Company performance criteria, individual performance criteria, and continued employment through the payment date. The short-term cash-based incentive awards granted in 2021 were paid in March 2022.
Share-Based Awards and Cash-Based Awards Compensation Expense
A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||
|
| 2023 |
| 2022 |
| 2023 |
| 2022 | ||||
Share-based compensation included in: | | |
| | |
| | |
| | |
|
General and administrative expenses | | $ | 2,087 | | $ | 2,014 | | $ | 4,009 | | $ | 2,534 |
Cash-based incentive compensation included in: | |
|
| |
|
| |
|
| |
|
|
Lease operating expense(1) | |
| 321 | |
| 206 | |
| 1,568 | |
| 462 |
General and administrative expenses(1) | |
| 899 | |
| 646 | |
| 6,869 | |
| 2,603 |
Total charged to operating income (loss) | | $ | 3,307 | | $ | 2,866 | | $ | 12,446 | | $ | 5,599 |
| | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | ||||||||
|
| 2022 |
| 2021 |
| 2022 |
| 2021 | ||||
Share-based compensation included in: | | |
| | |
| | |
| | |
|
General and administrative expenses | | $ | 2,645 | | $ | 858 | | $ | 5,179 | | $ | 1,779 |
Cash-based incentive compensation included in: | |
|
| |
|
| |
|
| |
|
|
Lease operating expense(1) | |
| 1,532 | |
| 1,119 | |
| 1,994 | |
| 2,774 |
General and administrative expenses(1) | |
| 3,559 | |
| 2,809 | |
| 6,164 | |
| 8,167 |
Total charged to operating income (loss) | | $ | 7,736 | | $ | 4,786 | | $ | 13,337 | | $ | 12,720 |
(1) | Includes adjustments of accruals to actual payments. |
20
NOTE 109 — INCOME TAXES
Tax BenefitExpense (Benefit) and Tax Rate
For the three months ended SeptemberJune 30, 2023, the Company recognized income tax expense of $3.0 million. Primarily as a result of changes in our valuation allowance on our deferred tax assets, our effective tax rate for the three months ended June 30, 2023 is not meaningful. For the three months ended June 30, 2022, the Company recognized income tax expense of $16.4$31.1 million for an effective tax rate of 19.7%20.1%.
For the threesix months ended SeptemberJune 30, 20212023, the Company recognized income tax benefitexpense of $5.9$11.6 million for an effective tax rate of 13.5%45.6%.
For the ninesix months ended SeptemberJune 30, 2022, the Company recognized income tax expense of $46.8$30.4 million for an effective tax rate of 20.0%20.1%. For the nine months ended September 30, 2021, the Company recognized income tax benefit of $18.8 million for an effective tax rate of 17.3%.
For the three and ninesix months ended SeptemberJune 30, 20222023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and 2021,adjustments to the valuation allowance. For the three and six months ended June 30, 2022, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to the valuation allowance.
Calculation of Interim Provision for Income Tax.
Historically, the Company has calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full year to income (loss) for the interim period. In the second quarter of 2023, the Company concluded that it could not calculate a reliable estimate of the annual effective tax rate. Accordingly, the Company computed the effective tax rate for the six-month period ending June 30, 2023 using actual results.
Valuation Allowance
Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on deferred tax assets, the Company considers whether it is more likely than not that some portion or all of them will not be realized.
As of SeptemberJune 30, 2022,2023 and December 31, 2021,2022, the valuation allowance was $15.2$19.8 million and $24.4$15.3 million, respectively, and relates primarily to state net operating losses and the disallowed interest expense limitation carryover.
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Income Taxes Receivable, Refunds and Payments
As of SeptemberJune 30, 20222023, the Company has a federal income tax receivable of $1.7 million and state income tax receivable of $0.2 million. As of December 31, 2021,2022, the Company did not have any outstanding current income taxes receivable. During the ninethree and six months ended SeptemberJune 30, 20222023, the Company did not receive any income tax refunds and made federal income tax payments of $5.2$2.2 million and state income tax payments of $0.3 million. During the ninethree and six months ended SeptemberJune 30, 2021,2022, the Company did not receive any income tax refunds or make any income tax payments of significance.
The tax years 2019 through 20212022 remain open to examination by the tax jurisdictions to which the Company is subject.
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NOTE 1110 — EARNINGS PER SHARE
The following table presents the calculation of basic and diluted (loss) earnings per common share (in thousands, except per share amounts):
| | | | | | | | | | | | �� | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||||||||||
|
| 2022 |
| 2021 |
| 2022 |
| 2021 |
| 2023 |
| 2022 |
| 2023 |
| 2022 | ||||||||
Net income (loss) | | $ | 66,721 | | $ | (37,964) | | $ | 187,700 | | $ | (90,382) | ||||||||||||
Net (loss) income | | $ | (12,109) | | $ | 123,436 | | $ | 13,896 | | $ | 120,979 | ||||||||||||
Less portion allocated to nonvested shares | |
| 1,265 | |
| — | |
| 2,166 | |
| — | |
| — | |
| — | |
| 243 | |
| — |
Net income (loss) allocated to common shares | | $ | 65,456 | | $ | (37,964) | | $ | 185,534 | | $ | (90,382) | ||||||||||||
Net (loss) income allocated to common shares | | $ | (12,109) | | $ | 123,436 | | $ | 13,653 | | $ | 120,979 | ||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
Weighted average common shares outstanding - basic | |
| 143,116 | |
| 142,297 | |
| 143,026 | |
| 142,231 | |
| 146,452 | |
| 143,020 | |
| 146,435 | |
| 142,981 |
Dilutive effect of securities | | | 2,766 | | | — | | | 1,670 | | | — | | | — | | | 1,505 | | | 2,610 | | | 1,113 |
Weighted average common shares outstanding - diluted | | | 145,882 | | | 142,297 | | | 144,696 | | | 142,231 | | | 146,452 | | | 144,525 | | | 149,045 | | | 144,094 |
Earnings per common share: | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | 0.46 | | $ | (0.27) | | $ | 1.30 | | $ | (0.64) | | $ | (0.08) | | $ | 0.86 | | $ | 0.09 | | $ | 0.85 |
Diluted | | | 0.46 | | | (0.27) | | | 1.30 | | | (0.64) | | | (0.08) | | | 0.85 | | | 0.09 | | | 0.84 |
| | | | | | | | | | | | | | | | | | | | | | | | |
Shares excluded due to being anti-dilutive (weighted average) | | | — | | | 1,973 | | | — | | | 1,266 | | | 2,909 | | | — | | | — | | | — |
NOTE 1211 — CONTINGENCIES
Appeal with the Office of Natural Resources Revenue (“ONRR”) – In 2009, W&T recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through subsea pipeline systems owned by the Company. In 2010, the ONRR audited calculations and support related to this usage fee, and in 2010, ONRR notified the Company that they had disallowed approximately $4.7 million of the reductions taken. The Company recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, the Company disagrees with the position taken by the ONRR. W&T filed an appeal with the ONRR, which ultimately led to the Company posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the Interior Board of Land Appeals decision. The cash collateral held by the surety was subsequently returned to the Company during the first quarter of 2020. The Company has continued to pursue its legal rights and, at present, the case is in front of the U.S. District Court for the Eastern District of Louisiana where both parties have filed cross-motions for summary judgment and opposition briefs. W&T has filed a Reply in support of its Motion for Summary Judgment and the government has in turn filed its Reply brief. With briefing now completed, the Company is waiting for the district court’s ruling on the merits. In compliance with the ONRR’s request for W&T to periodically increase the surety posted in the appeal to cover pre- and post-judgement interest, the sum of the bond posted is $8.2$8.9 million as of SeptemberJune 30, 2022.2023.
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Civil Penalties – In January 2021, W&T executed a Settlement Agreement with the Bureau of Safety and Environmental Enforcement (“BSEE”) which resolved nine pending civil penalties issued by BSEE. The civil penalties pertained to Incidents of Non-Compliance (“INC”) issued by BSEE alleging regulatory non-compliance at separate offshore locations on various dates between July 2012 and January 2018, with the proposed civil penalty amounts totaling $7.7 million. Under the Settlement Agreement, W&T willagreed to pay a total of $720,000 in three annual installments. The first, second and secondfinal installments were paid in March 2021, and March 2022 and February 2023, respectively. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022, which is on schedule to be completed before the deadline. Additionally in October 2022, BSEE issued a civil penalty assessment for approximately $24,000 for an INC that occurred at one of the Company’s properties in 2021.
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Retained Liabilities Related to Divested Property InterestsContingent Decommissioning Obligations – The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. For example, recent historical declinesCertain counterparties in commodity prices created an environment where there is an increased riskpast divestiture transactions or third parties in existing leases that owners and/have filed for bankruptcy protection or operators of interests purchased from the Companyundergone associated reorganizations may no longernot be able to satisfy plugging orperform required abandonment obligations that attach to those interests. In that event, dueobligations. Due to operation of law, W&T may be required to assume plugging or abandonmentdecommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. W&T no longer owns these assets nor are they related to current operations.
During 2021, as a result of the declaration of bankruptcy by a third party that is the indirect successor in title to certain offshore interests that were previously divested by the Company, W&T recorded aan initial contingent loss contingency accrual of $4.5 million related to anticipated decommissioning obligations, which was reflected in Other (income) expense, net on the Condensed Consolidated Statements of Operations in the period recorded. The Company reassessed the recorded contingent loss related to the anticipated costdecommissioning obligations throughout 2022, and as of December 31, 2022, the total loss contingency recorded was $20.4 million. The additional $15.9 million recorded in 2022 was reflected in Other (income) expense, net on the Condensed Consolidated Statements of Operations in the period recorded. During the six months ended June 30, 2023, the Company incurred $3.4 million in costs related to decommissionthese decommissioning obligations and reduced the liability accordingly. As of June 30, 2023, the remaining loss contingency recorded related to the anticipated decommissioning obligations was $17.0 million.
Although it is reasonably possible that the Company could receive additional state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise the Company’s opinion regarding the outcome of certain wells, pipelines,notices or matters, and production facilities forsuch developments could have a material adverse effect on the Company’s results of operations in the period in which the amounts are accrued and the Company’s cash flows in the period in which the amounts are paid. To the extent that the Company may receive decommissioning orders from BSEE. W&T no longer ownsdoes incur costs associated with these assets nor are they related to current operations.properties in future periods, W&T intends to seek contribution from other parties that owned an interest in the facilities. As of September 30, 2022, W&T estimates that the Company’s potential liability to fund decommissioning of previously divested property interests is $4.9 million, which has been accrued as a loss contingency.
AAIT Litigation – In August 2022, the Company’s primary information technology service provider, All About IT, Inc. (“AAIT”), notified the Company of its intention to cease providing services to the Company by September 2, 2022. The Company has begun the process of moving certain of these services within the Company and transitioning the remaining services to new service providers (the “transition process”). On August 19, 2022, the Company filed in the District Court of Harris County, Texas a petition for a temporary restraining order, temporary injunction, and permanent injunction seeking, among other things, to restrain AAIT from ceasing to provide services to the Company until the transition process is complete. On September 14, 2022, AAIT removed the matter to the United States District Court for the Southern District of Texas. On September 16, 2022, the Company and AAIT mutually agreed to the terms of an agreed order of the court providing for a temporary injunction for a period of a minimum of 60 days from the date of the order and up to a maximum of 120 days at the Company’s option, during which AAIT would continue to provide information technology services to the Company and assist with the transition process. By agreement of the parties, the agreed order also provided for the appointment of Hon. Gregg J. Costa (Ret.) as an independent adjudicator to assist in adjudicating ongoing disputes between the parties.
Other Claims – W&T is a party to various pending or threatened claims and complaints seeking damages or other remedies concerning commercial operations and other matters in the ordinary course of its business. In addition, claims or contingencies may arise related to matters occurring prior to the Company’s acquisition of properties or related to matters occurring subsequent to the Company’s sale of properties. In certain cases, W&T has indemnified the sellers of properties acquired, and in other cases, W&T has indemnified the buyers of properties sold. The Company is also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although W&T can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the consolidated financial position, results of operations or liquidity of the Company.
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NOTE 13 12 — SUBSEQUENT EVENTS RELATED PARTY TRANSACTIONS
On November 1, 2022,May 15, 2023, the $552.5 million principalCompany acquired a corporate aircraft from a company affiliated with and controlled by W&T’s CEO. The purchase price of the Senior Second Lien Notes were reclassified from long-term debt to current debt asaircraft was $19.1 million, which was paid using $9.0 million of cash on hand and through the assumption of the TVPX Loan, which had a resultfair market value of their November 1, 2023 maturity date. See Note 2 – Debt for additional information.
On November 7, 2022,$10.1 million on the Company entered into the Eleventh Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity date and Lender commitment to January 3, 2024, or in the event the Senior Second Lien Notes are not refinanced or replaced in full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023. Outstanding borrowings will accrue interest at SOFR plus 6.0% per annum. The commitment fee for the unused portion of available borrowing amounts will be 3.0% per annum. In connection with the Eleventh Amendment, the Company paid to Calculus an extension fee of $100,000.assumption. The terms of the Eleventh Amendmentthis transaction were reviewed and approved by the Audit Committee of the Company’s Board of DirectorsDirectors. See Note 2 – Debt for additional information.
The aircraft was purchased as part of a series of transactions pursuant to which the Company restructured the compensation for its Named Executive Officers. Prior to the Company’s purchase of the Company.aircraft, the Company used the aircraft for business purposes, and the CEO also used the aircraft for personal purposes. Both the Company’s use for business purposes and the CEO’s unlimited use for personal purposes were paid for by the Company pursuant to the CEO’s prior employment agreement. In connection with the Company’s efforts to significantly reduce overall executive compensation, including perquisite compensation Mr. Krohn was receiving for personal use of the aircraft, on April 20, 2023, the Company entered into an amendment to the employment agreement with the CEO which requires that the Company be reimbursed for personal use of the aircraft in accordance with the Company’s aircraft use policy.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to those financial statements included in Part I, Item 1 of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 20212022 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and the Results of Operations included in Part II, Item 7 of our 20212022 Annual Report. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “W&T” or the “Company” are to W&T Offshore, Inc. and its wholly owned subsidiaries.
Cautionary Note Regarding Forward-Looking Statements
The information in this Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These forward-looking statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Although we believe that these forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. TheseReaders are cautioned not to place undue reliance on forward-looking statements, are based onwhich speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.
The information included in this Quarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our currentexpected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations and assumptions about future events and are based on currently available information as to the outcomeour future financial position, liquidity, cash flows, results of operations and timingbusiness strategy, potential acquisition opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and operating costs, reserves, hedging activities, capital expenditures, return of future events.
These forward-looking statements are subject to risks, uncertaintiescapital, improvement of recovery factors and assumptions, most of which are difficult to predict and many of which are beyond our control. If the risks or uncertainties materialize or the assumptions prove incorrect, ourother guidance. Actual results may differ from anticipated results, sometimes materially, from those expressed or implied byand reported results should not be considered an indication of future performance. For any such forward-looking statements and assumptions. These statements are based on certainstatement that includes a statement of the assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, estimates, expected future developments and other factorsor bases underlying such forward-looking statement, we caution that, while we believe are appropriatesuch assumptions or bases to be reasonable and make them in the circumstances. good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Known material risks that may affect our financial condition and results of operations are discussed in Part I, Item 1A, Risk Factors, and market risks are discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our 20212022 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the SEC.
Reserve engineering is a process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGLs and natural gas that are ultimately recovered.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
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Overview
We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of SeptemberJune 30, 2022,2023, we hold working interests in 4746 producing offshore fields in federal and state waters (45 fields producing and 2 fields capable of producing, which(which include 3938 fields in federal waters and 8 in state waters). We currently have under lease approximately 622,000578,000 gross acres (449,500(419,000 net acres) spanning across the outer continental shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama state waters, 449,000416,500 gross acres on the conventional shelf and approximately 165,000153,500 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC and, W & T&T Energy VI, LLC, each of which are Delaware limited liability companies, and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements – Note 6 – Joint Venture Drilling Program under Part I, Item 1 in this Quarterly Report.Monza.
Known Trends and Uncertainties
Volatility in Oil, NGL and Natural Gas Prices – Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events.
In addition to such industry-specific risks, the global public health crisis associated with COVID-19 has created uncertainty for global economic activity since March 2020. Since 2021, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. However, new variants of the virus continue to emerge and it is difficult to assess if such variants will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy because of the ongoing pandemic.
However, a high level of uncertainty remains regarding the volatility of energy supply and demand as a result of Russia’s full-scale invasion of Ukraine in February 2022. As a result of the war, several countries imposed sanctions on imports of crude oil and petroleum products from Russia. In addition, many international oil companies and other firms ended operations in Russia and limited or stopped trading Russia’s crude oil and petroleum products. These actions have reduced Russia’s oil production and caused crude oil prices to rise. Most recently, Russia has increased strikes on Ukraine which may result in further sanctions against Russia. Additionally in early October 2022 the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) announced a production cut of approximately two million barrels per day which has put additional upward pressure on oil prices. As a result, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves.
The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on October 12, 2022. WTI crude oil prices and NYMEX Henry Hub natural gas prices have decreased following the surge in prices during the first half of 2022, closing the thirdsecond quarter at approximately $80.00$70.66 per barrel and $6.50$2.48 per Mcf, respectively. Prior to the OPEC+ announcement, crude oil prices were generally decreasing in response to the overall indications of slowing global economic growth. While oil spot prices increased in the immediate aftermath of OPEC+’s announcement, theThe U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on July 11, 2023. The EIA expects the WTI spot price average to decrease to $85.98remain relatively flat in the third quarter of 2023 at $73.32 per barrel during the fourth quarter of 2022 as compared to the thirdsecond quarter 20222023 average of $93.07$73.49 per barrel. The EIA also expects the average Henry Hub spot price to average $7.70 per Mcf during the fourth quarter of 2022 as compared to $8.30increase during the third quarter of 2022.
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As2023 to $2.74 per Mcf as compared to the second quarter 2023 average of $2.25 per Mcf.
In June 2023 the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC Plus”) announced that prior year, spot prices remain high, likely as a resultproduction cuts of low inventoriesover 3.6 million barrels per day, which were valid until the end of 2023, had been extended until the end of 2024. OPEC also announced plans to further reduce production targets by an additional 1.4 million barrels per day beginning in January 2024. Saudi Arabia also announced plans in June to reduce the country’s output by over 1.0 million barrels per day beginning in July 2023. Despite these OPEC Plus production cuts, the EIA expects that the global oil markets will see an overall increase in oil supply during 2023 primarily because of growth from non-OPEC producers. In addition, increasing risk in the U.S. and continuedglobal banking sectors creates uncertainty surrounding the Russia-Ukraine conflictabout macroeconomic conditions and the relatedtheir potential effects on future oil demand growth, which has the potential to result in lower oil prices. These shifts in OPEC Plus production levels as well as the Russia-Ukraine war and gas supply. Per the EIA, average crude oil prices using the WTI daily spot price increasedrelated sanctions, and overall indicators of slowing global economic growth, continue to $98.96 per barrel during the nine months ended September 30, 2022 comparedcontribute to $65.05 per barrel during the nine months ended September 30, 2021 (52.1% increase). The NYMEX Henry Hub average daily natural gas spot price increased to $6.74 per Mcf for the nine months ended September 30, 2022 compared to $3.61 per Mcf during the nine months ended September 30, 2021 (87.0% increase).a high level of uncertainty surrounding energy supply and demand, putting additional pressure on commodity prices.
Rising Interest Rates and Inflation of Cost of Goods, Services and Personnel – Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. Continued inflationary pressures and increased commodity may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.
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The United States was measuredhas experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at 8.2% in September9.1% but has been gradually declining since the second half of 2022 byaccording to the Consumer Price Index,Index. As of June 2023, the highest in more than four decades. In addition,annual inflation rate had slowed to 3.0% according to the Consumer Price Index. Though inflation is currently on the decline, these inflationary pressures have caused the Federal Reserve has tightenedto tighten monetary policy by approving a series of increases to the Federal Funds Rate. On July 26, 2023, the Federal Reserve increased the Federal Funds Rate and signaled thatby another 0.25 percentage points, its eleventh hike since March 2022. This latest rate hike brought the Federal Reserve benchmark rate range to 5.25% to 5.50%. If inflation were to continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary action to bring inflation down and to ensure price stability, including further rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurtnegatively impact our business.
As a result of these factors, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.
Inflation Reduction Act of 2022 (the “IRA”)Planned and Unplanned Downtime –On August 16, 2022, President Biden signed the IRA into law. Several provisions in the IRAWe are expectedsubject to apply to our business. For instance, the IRA specifically directs the Department of the Interior (”DOI”) to accept the highest bids received for Lease Sale 257, which was vacated by US District Court for the District of Columbia in January 2022 and move forward with Lease Sales 259 and 261 in the Gulf of Mexico by March 31, 2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.
The IRA ties the issuance of offshore leases for wind development by the federal government to requirements to offer for sale federal oil and gas leases for a 10-year period of time. The IRA requires the federal government to offer for sale a minimum of 60 million acres for offshore oil and gas leases during the one-year period immediately preceding granting an offshore wind lease on the U.S. Outer Continental Shelf.
The IRA also increases the minimum oil and gas royalty rate for new offshore leases from the current 12.50% to 16.67% and caps the royalty rate at 18.75% for 10 years. The 18.75% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters. This provision does not affect existing offshore leases.
Furthermore, the IRA imposes a methane emissions charge. The IRA amends the federal Clean Air Act to impose a fee on emissions of methane from sources required to report their greenhouse gas emissions to the U.S. Environmental Protection Agency (“EPA”), including sources in the offshore and onshore oil and gasdowntime events impacting production, and onshore processing, transmission and compression,transportation, gathering and boosting station source categories. Forprocessing of our production.Unplanned or planned downtime may be caused, for example, by certain regulatory requirements and inspections or third-party pipeline maintenance. During such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024. In 2025, the charge increases to $1,200 per metric ton of methane. For calendar year 2026 and thereafter, the fee will be $1,500 per metric ton of methane. Calculation of the chargedowntime, our operating income is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, andnegatively impacted. During the first fee payment will be in 2025 based on 2024 data. The methane emissions charge may increasequarter of 2023, our operating costsproduction was temporarily impacted by planned maintenance at Mobile Bay and adversely affectunplanned downtime at other non-operated fields. During the second quarter of 2023, our business.production was negatively impacted by unplanned downtime due to third-party pipeline maintenance and production downtime at non-operated fields.
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Bureau of Ocean Energy Management (“BOEM”) Matters – In order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurance that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. AsThe Department of Interior is reviewing many BOEM regulations and proposed a rule in June 2023 that would revise BOEM’s criteria for determining whether lessees are being reviewed by the Department of the Interior,required to provide supplemental financial insurance. Accordingly, we may be subject to additional financial assurance requirements in the future. As of the filing date of this Quarterly Report, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to supplemental financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.
Surety Bond Collateral – Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes or bonds associated with our appeals of Department of the Interior’s orders or demands have on occasion requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. No additional demands were made to us by sureties during 2022the six months ended June 30, 2023 and we do not have surety bond collateral outstanding as of the filing date of this Quarterly Report and we currently do not have surety bond collateral outstanding.Report. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.
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Results of Operations
Three Months Ended SeptemberJune 30, 20222023 Compared to the Three Months Ended SeptemberJune 30, 20212022
Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss, net in our Condensed Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:
| | | | | | | | | | |
| Three Months Ended September 30, | Three Months Ended June 30, | ||||||||
| 2022 |
| 2021 | 2023 |
| 2022 | ||||
Oil | 49.0 | % | | 55.4 | % | 71.3 | % | | 58.1 | % |
NGLs | 6.3 | % | | 9.1 | % | 8.2 | % | | 6.1 | % |
Natural gas | 42.7 | % | | 33.7 | % | 18.6 | % | | 33.8 | % |
Other | 2.0 | % | | 1.8 | % | 1.9 | % | | 2.0 | % |
28
The information below provides a discussion of, and an analysis of significant variancevariances in, our oil, natural gas and NGL revenues, production volumes and realized sales prices (which exclude the effect of hedging unless otherwise stated) for the three months ended SeptemberJune 30, 20222023 and 2021:2022:
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| | Three Months Ended September 30, | | Three Months Ended June 30, | | | | |||||||||||
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| 2022 |
| 2021 |
| | Change |
| 2023 |
| 2022 |
| | Change | ||||
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| (In thousands, except realized sales price data) |
| (In thousands, except realized sales price data) | ||||||||||||||
Revenues: | | | | | | | | | | | | | | | | | | |
Oil | | $ | 130,560 | | $ | 74,265 | | $ | 56,295 | | $ | 89,982 | | $ | 159,264 | | $ | (69,282) |
NGLs | |
| 16,875 | |
| 12,205 | |
| 4,670 | |
| 10,385 | |
| 16,735 | |
| (6,350) |
Natural gas | |
| 113,673 | |
| 45,137 | |
| 68,536 | |
| 23,438 | |
| 92,413 | |
| (68,975) |
Other | |
| 5,377 | |
| 2,339 | |
| 3,038 | |
| 2,376 | |
| 5,396 | |
| (3,020) |
Total revenues | |
| 266,485 | |
| 133,946 | |
| 132,539 | |
| 126,181 | |
| 273,808 | |
| (147,627) |
| | | | | | | | | | | | | | | | | | |
Production Volumes: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Oil (MBbls) | |
| 1,447 | |
| 1,083 | |
| 364 | |
| 1,254 | |
| 1,476 | |
| (222) |
NGLs (MBbls) | |
| 454 | |
| 376 | |
| 78 | |
| 443 | |
| 384 | |
| 59 |
Natural gas (MMcf) | |
| 11,499 | |
| 10,481 | |
| 1,018 | |
| 10,023 | |
| 11,995 | |
| (1,972) |
Total oil equivalent (MBoe) | |
| 3,818 | |
| 3,206 | |
| 612 | |
| 3,368 | |
| 3,859 | |
| (491) |
| | | | | | | | | | | | | | | | | | |
Average daily equivalent sales (Boe/day) | | | 41,500 | | | 34,848 | | | 6,652 | | | 37,011 | | | 42,407 | | | (5,396) |
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Average realized sales prices: | |
| | |
| | |
| | |
| | |
| | |
| |
Oil ($/Bbl) | | $ | 90.23 | | $ | 68.57 | |
| 21.66 | | $ | 71.76 | | $ | 107.90 | |
| (36.14) |
NGLs ($/Bbl) | |
| 37.17 | |
| 32.46 | |
| 4.71 | |
| 23.44 | |
| 43.58 | |
| (20.14) |
Natural gas ($/Mcf) | |
| 9.89 | |
| 4.31 | |
| 5.58 | |
| 2.34 | |
| 7.70 | |
| (5.36) |
Oil equivalent ($/Boe) | | | 68.39 | | | 41.05 | | | 27.34 | | | 36.76 | | | 69.55 | | | (32.79) |
Oil equivalent ($/Boe), including realized commodity derivatives(1) | |
| 50.86 | |
| 31.95 | |
| 18.91 | |
| 36.67 | |
| 94.20 | |
| (57.53) |
(1) | Excludes the effects of premium |
| ||
Volume measurements not previously defined: |
|
|
MBbls — thousand barrels for crude oil, condensate or NGLs |
| Mcf — thousand cubic feet |
MBoe — thousand barrels of oil equivalent | | MMcf – million cubic feet |
25
Changes in average sales prices (which does not give effect to hedging) and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended SeptemberJune 30, 20222023 and 20212022 (in thousands):
| | | | | | | | | | | | | | | | |
| Price |
| Volume | | Total | Price |
| Volume | | Total | ||||||
Oil | $ | 31,321 | | $ | 24,975 | | $ | 56,296 | $ | (45,386) | | $ | (23,896) | | $ | (69,282) |
NGLs |
| 2,124 | |
| 2,546 | |
| 4,670 |
| (9,152) | | | 2,802 | |
| (6,350) |
Natural gas |
| 64,150 | | | 4,385 | |
| 68,535 |
| (53,782) | | | (15,193) | |
| (68,975) |
| $ | 97,595 | | $ | 31,906 | | $ | 129,501 | $ | (108,320) | | $ | (36,287) | | $ | (144,607) |
29
Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet (“LLS”), and Heavy Louisiana Sweet (“HLS”). Similar to crude oil prices, the differentials for our offshore crude oil have also been volatile in the past. The monthly average differentialsdifferential of WTI versus HLSLLS and LLSHLS for the three months ended SeptemberJune 30, 20222023 was favorable to the Company and increased on average by approximately $0.27$0.35 and $1.00$1.30 per barrel, respectively.respectively, compared to the same period in 2022. The monthly average differential for WTI versus Poseidon for the three months ended June 30, 2023 was unfavorable to the Company and declined on average by approximately $2.74$1.12 per barrel compared to the same period in 2021.2022.
Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the three months ended SeptemberJune 30, 20222023 compared to the three months ended SeptemberJune 30, 2021,2022, average prices for domestic ethane increaseddecreased by 58.0%64.0% and average domestic propane prices increaseddecreased by 61.8%68.6% as measured using a price index for Mount Belvieu. The average prices for normal butane increaseddecreased by 7.8%49.8% while other domestic NGL components decreased between 7.2%46.1% and 11.5%48.1% for the three months ended SeptemberJune 30, 20222023 compared to the same period in 2021.2022. The change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.
The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. The sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.
Oil, NGLs, and Natural Gas Volumes – Production volumes increaseddecreased by 612491 MBoe to 3,8183,368 MBoe induring the three months ended SeptemberJune 30, 20222023 compared to the same period in 2021,2022, primarily due to the acquisitionthird party deepwater pipeline maintenance and production downtime at non-operated fields.
26
Operating Expenses
The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes:
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| 2023 |
| 2022 |
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| 2022 |
| 2021 |
| | Change | |||||||||||
| | | | | | | | | | | | (In thousands, except per Boe data) | ||||||
Operating expenses: | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | $ | 59,010 | | $ | 39,490 | | $ | 19,520 | | $ | 66,021 | | $ | 52,976 | | $ | 13,045 |
Gathering, transportation and production taxes | | | 12,199 | | | 6,593 | | | 5,606 | | | 6,802 | | | 9,181 | | | (2,379) |
Depreciation, depletion, amortization and accretion |
| | 34,113 | | | 26,291 |
| | 7,822 |
| | 35,894 | | | 34,360 |
| | 1,534 |
General and administrative expenses | | | 23,047 | | | 13,391 | | | 9,656 | | | 17,393 | | | 14,967 | | | 2,426 |
Total operating expenses | | $ | 128,369 | | $ | 85,765 | | $ | 42,604 | | $ | 126,110 | | $ | 111,484 | | $ | 14,626 |
| | | | | | | | | | | | | | | | | | |
Average per Boe ($/Boe): | |
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| |
|
| |
|
| |
|
| |
|
| |
|
|
Lease operating expenses | | $ | 15.46 | | $ | 12.32 | | $ | 3.14 | | $ | 19.60 | | $ | 13.73 | | $ | 5.87 |
Gathering, transportation and production taxes | |
| 3.20 | | | 2.06 | |
| 1.14 | |
| 2.02 | | | 2.38 | |
| (0.36) |
DD&A | |
| 8.93 | | | 8.20 | |
| 0.73 | |
| 10.66 | | | 8.90 | |
| 1.76 |
G&A expenses | |
| 6.04 | | | 4.18 | |
| 1.86 | |
| 5.16 | | | 3.88 | |
| 1.28 |
Operating expenses | | $ | 33.63 | | $ | 26.76 | | $ | 6.87 | | $ | 37.44 | | $ | 28.89 | | $ | 8.55 |
30
Lease operating expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased $19.5$13.0 million to $59.0$66.0 million for the three months ended SeptemberJune 30, 20222023 compared to $39.5$53.0 million for the three months ended SeptemberJune 30, 2021.2022. On a component basis, base lease operating expenses increased $15.0 $4.7 million, workover expenses increased $1.0$6.3 million, and facilities maintenance expense increased $4.3 million, and hurricane repairs decreased $0.8$2.0 million.
Base lease operating expenses increased primarily due to increased expenses related to the fields acquired during the first two quarters of 2022, increased contract labor, equipment rental, and transportation costs at various fields, and increased insurance expense. The increases in workover expenses and facilities maintenance expenseexpenses were due to an increase in projects undertaken. Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. Lastly, during the three months ended September 30, 2021 we incurred $0.8 million in expenses related to repairs associated with hurricanes that we did not incur during the three months ended September 30, 2022.
Gathering, transportation and production taxes – Gathering, transportation and production taxes increased $5.6decreased $2.4 million infor the three months ended SeptemberJune 30, 20222023 compared to the three months ended SeptemberJune 30, 2021 p2022 rimarily due to a new transportation contract related to the properties acquireddecreases in the first half of 2022. Additionally, the increaseproduction volumes and decreases in realized natural gas and NGL prices along with an increase in oil, NGL and natural gas production during the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 caused gathering, transportation and production taxes to increase.prices.
Depreciation, depletion, amortization and accretion (“DD&A”) – DD&A, which includes accretion for ARO, increased $1.5 million for the three months ended June 30, 2023 as compared to the three months ended June 30, 2022. The DD&A rate increased to $8.93$10.66 per Boe for the three months ended SeptemberJune 30, 20222023 from $8.20$8.90 per Boe for the three months ended SeptemberJune 30, 2021. On a nominal basis, DD&A2022. The increased $7.8 million for the three months ended September 30, 2022 as compared to the three months ended September 30, 2021expense was primarily due to an increased DD&A per Boe rate and, to a lesser extent, the increase in production volumes. The DD&A rate per Boe increased mostly as a result of increases in capital expenditures and future development costs included in the depreciable base associated with an increase in economic proved undeveloped wells due to higher oilincreased capital spending and gas prices compared toincreased future development costs since the smaller increase in proved reserves over the comparable prior year period.second quarter of 2022, partially offset by lower production volumes.
General and administrative expenses (“G&A”) – G&A increased $9.7$2.4 million, to $23.0$17.4 million for the three months ended SeptemberJune 30, 20222023 as compared to $13.4$15.0 million for the three months ended SeptemberJune 30, 2021. 2022. The increase is primarily due to non-recurring professional services incurred during the third quarter of 2022 after a review of processesincreased payroll costs, incentive compensation expense and controls within our information technology department, including additional non-recurring expenses associated with the process of transitioning substantially all of our information technology infrastructure and related services internally or to other providers. Further, we have incurred additional legal expenses in conjunction therewith. Additionally, weexpenses. We incurred increased incentive compensation costs related to the higher grant date fair value of RSU and PSUshare-based compensation awards granted during 2022 as compared to the valuesecond quarter of awards granted in 2021.2023.
27
Other Income and Expense
The following table presents the components of other income and expense for the periods presented and corresponding changes:
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| | Three Months Ended June 30, | | | | |||||||||||||
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| 2023 |
| 2022 |
| | Change | |||||||||||
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| | Three Months Ended September 30, | ||||||||||||||||
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| 2022 |
| 2021 |
| | Change | |||||||||||
| | | | | | | | | | | (In thousands) | |||||||
Other income and expenses: | | | | | | | | | | | | | | | | | | |
Derivative loss | | $ | 38,749 | | $ | 73,137 | | $ | (34,388) | |||||||||
Derivative (gain) loss, net | | $ | (829) | | $ | (8,854) | | $ | 8,025 | |||||||||
Interest expense, net |
| | 16,849 | | | 18,910 |
| | (2,061) |
| | 10,323 | | | 18,183 |
| | (7,860) |
Other (income) expense, net |
| | (600) | | | — |
| | (600) |
| | (311) | | | (1,534) |
| | 1,223 |
Income tax expense (benefit) |
| | 16,397 | | | (5,902) |
| | 22,299 | |||||||||
Income tax expense |
| | 2,997 | | | 31,093 |
| | (28,096) |
31
Derivative (gain) loss, net – During the three months ended SeptemberJune 30, 2022,2023, the $38.7$0.8 million derivative lossgain recorded for crude oil and natural gas derivative contracts consists of $132.3 million of realized losses on settled contracts and premium amortization and $93.5$1.1 million of unrealized gain net from the increase in the fair value of open contracts.contracts, partially offset by $0.3 million of realized losses. During the three months ended SeptemberJune 30, 2021,2022, the $73.1$8.9 million derivative lossgain recorded for crude oil and natural gas derivative contracts consisted of $30.0$79.7 million in realized lossesgains and $43.1$70.8 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.
In the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of certain outstanding purchased calls covering the second half of 2022 through the first quarter of 2025 by increasing the weighted-average strike prices. These transactions resulted in net cash proceeds of $105.3 million.
Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through April 2028, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Financial Statements – Note 8 –Derivative4 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information.
Interest expense, net – Interest expense, net, was $16.8$10.3 million and $18.9$18.2 million for the three months ended SeptemberJune 30, 20222023 and 2021,2022, respectively. The decrease of $2.1$7.9 million in 20222023 is primarily due to the redemption of the 9.75% Senior Second Lien Notes which occurred in February 2023, lower interest expense on the lower outstanding principal balance of the Term Loan and increased interest income. These decreases were partially offset by interest expense incurred on the 11.75% Senior Second Lien Notes issued in late January 2023.
Income tax expense (benefit) – Income tax expense for the three months ended SeptemberJune 30, 2023 and June 30, 2022 was $16.4$3.0 million compared to an income tax benefit of $5.9and $31.1 million, during the three months ended September 30, 2021.respectively. For the three months ended SeptemberJune 30, 2023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and adjustments to the valuation allowance. For the three months ended June 30, 2022, and 2021, our incomethe Company’s effective tax benefitrate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to the valuation allowance. Primarily as a result of changes in our valuation allowance. Ourallowance on our deferred tax assets, our effective tax rate was 19.7% and 13.5% for the three months ended SeptemberJune 30, 2022 and 2021, respectively.2023 is not meaningful. The company’s effective tax rate was 20.1% for the three months ended June 30 2022.
As of SeptemberJune 30, 2022,2023, the valuation allowance on our deferred tax assets was $15.2$19.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 10 –Income9 – Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.
Nine28
Six Months Ended SeptemberJune 30, 20222023 Compared to the NineSix Months Ended SeptemberJune 30, 20212022
Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss, net in our Condensed Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:
| | | | | | | | | | |
| Nine Months Ended September 30, | Six Months Ended June 30, | ||||||||
| 2022 |
| 2021 | 2023 |
| 2022 | ||||
Oil | 56.4 | % | | 61.3 | % | 72.6 | % | | 60.7 | % |
NGLs | 6.5 | % | | 7.7 | % | 7.0 | % | | 6.6 | % |
Natural gas | 35.2 | % | | 29.0 | % | 18.7 | % | | 30.9 | % |
Other | 1.9 | % | | 2.0 | % | 1.7 | % | | 1.8 | % |
32
The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and realized sales prices (which exclude the effect of hedging unless otherwise stated) for the ninesix months ended SeptemberJune 30, 20222023 and 2021:2022:
| | | | | | | | | | |||||||||
| | Six Months Ended June 30, | | | | |||||||||||||
| | 2023 |
| 2022 |
| | Change | |||||||||||
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| | Nine Months Ended September 30, | ||||||||||||||||
| | 2022 |
| 2021 |
| | Change | |||||||||||
| | | | | | | | | | | | (In thousands, except realized sales price data) | ||||||
Revenues: | | | | | | | | | | | | | | | | | | |
Oil | | $ | 412,526 | | $ | 240,418 | | $ | 172,108 | | $ | 186,982 | | $ | 281,966 | | $ | (94,984) |
NGLs | |
| 47,430 | |
| 30,397 | |
| 17,033 | |
| 18,180 | |
| 30,555 | |
| (12,375) |
Natural gas | |
| 257,452 | |
| 113,816 | |
| 143,636 | |
| 48,242 | |
| 143,779 | |
| (95,537) |
Other | |
| 13,889 | |
| 7,790 | |
| 6,099 | |
| 4,502 | |
| 8,512 | |
| (4,010) |
Total revenues | | $ | 731,297 | | $ | 392,421 | | $ | 338,876 | | $ | 257,906 | | $ | 464,812 | | $ | (206,906) |
| | | | | | | | | | | | | | | | | | |
Production Volumes: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Oil (MBbls) | |
| 4,227 | |
| 3,812 | |
| 415 | |
| 2,604 | |
| 2,780 | |
| (176) |
NGLs (MBbls) | |
| 1,187 | |
| 1,105 | |
| 82 | |
| 738 | |
| 733 | |
| 5 |
Natural gas (MMcf) | |
| 33,965 | |
| 33,469 | |
| 496 | |
| 17,699 | |
| 22,466 | |
| (4,767) |
Total oil equivalent (MBoe) | |
| 11,075 | | | 10,495 | | | 580 | |
| 6,292 | | | 7,257 | | | (965) |
| | | | | | | | | | | | | | | | | | |
Average daily equivalent sales (Boe/day) | | | 40,568 | | | 38,444 | | | 2,124 | | | 34,762 | | | 40,094 | | | (5,332) |
| | | | | | | | | | | | | | | | | | |
Average realized sales prices: | |
| | | | | | | | |
| | | | | | | |
Oil ($/Bbl) | | $ | 97.59 | | $ | 63.07 | | $ | 34.52 | | $ | 71.81 | | $ | 101.43 | | $ | (29.62) |
NGLs ($/Bbl) | |
| 39.96 | |
| 27.51 | |
| 12.45 | |
| 24.63 | |
| 41.68 | |
| (17.05) |
Natural gas ($/Mcf) | |
| 7.58 | |
| 3.40 | |
| 4.18 | |
| 2.73 | |
| 6.40 | |
| (3.67) |
Oil equivalent ($/Boe) | | | 64.78 | | | 36.65 | | | 28.13 | | | 40.27 | | | 62.88 | | | (22.61) |
Oil equivalent ($/Boe), including realized commodity derivatives(1) | |
| 63.76 | |
| 31.71 | |
| 32.05 | |
| 40.19 | |
| 70.53 | |
| (30.34) |
(1) | Excludes the effects of premium amortization and write-offs. |
29
Changes in average sales prices (which does not give effect to hedging) and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the ninesix months ended SeptemberJune 30, 20222023 and 20212022 (in thousands):
| | | | | | | | | | | | | | | | |
| Price |
| Volume | | Total | Price |
| Volume | | Total | ||||||
Oil | $ | 145,927 | | $ | 26,181 | | $ | 172,108 | $ | (77,129) | | $ | (17,855) | | $ | (94,984) |
NGLs |
| 14,897 | |
| 2,136 | |
| 17,033 |
| (12,751) | | $ | 376 | |
| (12,375) |
Natural gas |
| 141,950 | | | 1,686 | |
| 143,636 |
| (65,032) | | | (30,505) | |
| (95,537) |
| $ | 302,774 | | $ | 30,003 | | $ | 332,777 | $ | (154,912) | | $ | (47,984) | | $ | (202,896) |
Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, LLS, and HLS. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentialsdifferential of WTI versus PoseidonLLS for the six months ended June 30, 2023 was favorable to the Company and increased on average by approximately $0.31 per barrel, compared to the same period in 2022. The average differential of WTI versus HLS for the ninesix months ended SeptemberJune 30, 20222023 was favorable to the Company and remained flat compared to the same period in 2022. The average differential for WTI versus Poseidon for the six months ended June 30, 2023 was unfavorable to the Company and declined on average by approximately $2.30 and $0.26 per barrel, respectively. The monthly average differential for WTI versus LLS increased on average by approximately $0.32$0.86 per barrel compared to 2021.the same period in 2022.
33
Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the ninesix months ended SeptemberJune 30, 20222023 compared to the ninesix months ended SeptemberJune 30, 2021,2022, average prices for domestic ethane increaseddecreased by 65.5%53.3% and average domestic propane prices increaseddecreased by 15.5%58.4% as measured using a price index for Mount Belvieu. The average prices for normal butane decreased by 39.0% while other domestic NGLs components increaseddecreased between 21.1%38.9% and 34.0%41.3% for the ninesix months ended SeptemberJune 30, 20222023 compared to the same period in 2021.2022. The change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.
The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. The sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.
Oil, NGLs, and Natural Gas Volumes – Production volumes increaseddecreased by 580965 MBoe to 11,0756,292 MBoe during the ninesix months ended SeptemberJune 30, 2022 as2023 compared to production volumes during the nine months ended September 30, 2021.same period in 2022 primarily due to shut-ins related to field and well maintenance at Mobile Bay during the acquisitionfirst quarter of the Ship Shoal 230, South Marsh Island 27/Vermilion 191,2023 as well as third party deepwater pipeline maintenance and South Marsh Island 73production downtime at non-operated fields during the first and second quarters of 2022. See Financial Statements – Note 4 – Acquisitions under Part I, Item 12023.
30
Operating Expenses
The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes:
| | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Six Months Ended June 30, | | | | |||||||||||
| | 2022 |
| 2021 |
| | Change | | 2023 |
| 2022 |
| | Change | ||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| | (In thousands, except per Boe data) | | (In thousands, except per Boe data) | ||||||||||||||
Operating expenses: | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | $ | 155,397 | | $ | 129,399 | | $ | 25,998 | | $ | 131,207 | | $ | 96,387 | | $ | 34,820 |
Gathering, transportation and production taxes | | | 26,647 | | | 19,687 | | | 6,960 | | | 12,938 | | | 14,448 | | | (1,510) |
Depreciation, depletion, amortization and accretion | | | 99,384 | | | 83,879 |
| | 15,505 | | | 66,028 | | | 65,271 |
| | 757 |
General and administrative expenses | | | 51,790 | | | 38,090 | | | 13,700 | | | 37,312 | | | 28,743 | | | 8,569 |
Total operating expenses | | $ | 333,218 | | $ | 271,055 | | $ | 62,163 | | $ | 247,485 | | $ | 204,849 | | $ | 42,636 |
| | | | | | | | | | | | | | | | | | |
Average per Boe ($/Boe): | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Lease operating expenses | | $ | 14.03 | | $ | 12.33 | | $ | 1.70 | | $ | 20.85 | | $ | 13.28 | | $ | 7.57 |
Gathering, transportation and production taxes | |
| 2.41 | |
| 1.88 | |
| 0.53 | |
| 2.06 | |
| 1.99 | |
| 0.07 |
DD&A | |
| 8.97 | |
| 7.99 | |
| 0.98 | |
| 10.49 | |
| 8.99 | |
| 1.50 |
G&A expenses | |
| 4.68 | |
| 3.63 | |
| 1.05 | |
| 5.93 | |
| 3.96 | |
| 1.97 |
Operating expenses | | $ | 30.09 | | $ | 25.83 | | $ | 4.26 | | $ | 39.33 | | $ | 28.22 | | $ | 11.11 |
Lease operating expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased $26.0$34.8 million to $155.4$131.2 million for the ninesix months ended SeptemberJune 30, 20222023 compared to $129.4$96.4 million for the ninesix months ended SeptemberJune 30, 2021.2022. On a component basis, base lease operating expenses increased $16.8$16.0 million, workover expenses increased $4.3$8.4 million, facilities maintenance expense increased $9.1$10.7 million, and hurricane repairs decreased $4.2$0.3 million.
34
Base lease operating expenses increased primarily due to increased expenses related to a full six months of expenses at the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields acquired during the first half ofFebruary 2022 as well as increased contract labor, equipment rental, and transportation costs at various fields, and increased insurance expense. The increases in workover expenses and facilities maintenance expenseexpenses were due to an increase in projects undertaken. Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. Lastly, during the nine months ended September 30, 2021 we incurred $4.2 million in expenses related to repairs associated with hurricanes that we did not incur during the nine months ended September 30, 2022.
Gathering, transportation and production taxes – Gathering, transportation and production taxes increased $7.0decreased $1.5 million infor the ninesix months ended SeptemberJune 30, 20222023 compared to the ninesix months ended SeptemberJune 30, 20212022 primarily due to a newdecreases in production volumes and decreases in realized prices partially offset by the transportation contract related to the properties acquired in the first half ofFebruary 2022. Additionally, the increase in realized natural gas and NGL prices along with an increase in oil, NGL and natural gas production during the nine months ended September 30, 2022 as compared to the comparable prior year period caused gathering, transportation and production taxes to increase.
Depreciation, depletion, amortization and accretion – DD&A, which includes accretion for AROs,ARO, increased $0.8 million for the six months ended June 30, 2023 as compared to the six months ended June 30, 2022. The DD&A rate increased to $8.97$10.49 per Boe for the ninesix months ended SeptemberJune 30, 20222023 from $7.99$8.99 per Boe for the ninesix months ended SeptemberJune 30, 2021. On a nominal basis,2022. The slight increase in DD&A increased $15.5 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021expense was primarily due to a higher DD&A per Boe rate. The DD&A rate per Boe increased mostly as a result of increases in the capital expenditures and future development costs included in the depreciable base associated with an increase in economic proved undeveloped wells due to higher oil increased capital spending and gas prices compared toincreased future development costs since the smaller increase in proved reserves over the comparable prior year period.second quarter of 2022, partially offset by lower production volumes.
31
General and administrative expenses – G&A increased $13.7$8.6 million to $51.8$37.3 million for the ninesix months ended SeptemberJune 30, 20222023 as compared to $38.1$28.7 million for the ninesix months ended SeptemberJune 30, 2021.2022. The increase is primarily due to non-recurring professional servicesincreased payroll costs, incurredincentive compensation expense, and legal expenses. The increase was partially offset by a $2.2 million employee retention credit recorded during the third quarter of 2022 after a review of processes and controls within our information technology department, including additional non-recurring expenses associated with the process of transitioning substantially all of our information technology infrastructure and related services internally or to other providers. Further, we have incurred additional legal expenses in conjunction therewith. Additionally, wesix months ended June 30, 2023. We incurred increased incentive compensation costs related to the higher value of the short-term cash-based incentive compensation awards granted in 2022 as compared to the value of awards granted in 2021, the higher grant date fair value of RSU and PSU awards granted during 2022 as compared to the value of awards granted in 2021.2021, as well as share-based compensation awards granted during the second quarter of 2023.
Other Income and Expense
The following table presents the components of other income and expense for the periods presented and corresponding changes:
| | | | | | | | | | |||||||||
| | Six Months Ended June 30, | | | | |||||||||||||
| | 2023 |
| 2022 |
| | Change | |||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| ||||||||||||||||||
| | |||||||||||||||||
| | Nine Months Ended September 30, | ||||||||||||||||
| | 2022 |
| 2021 |
| | Change | |||||||||||
| | | | | | | | | | | (In thousands) | |||||||
Other income and expenses: | | | | | | | | | | | | | | | | | | |
Derivative loss | | $ | 109,892 | | $ | 179,156 | | $ | (69,264) | |||||||||
Derivative (gain) loss, net | | $ | (40,069) | | $ | 71,143 | | $ | (111,212) | |||||||||
Interest expense, net | | | 54,915 | | | 50,474 |
| | 4,441 | | | 25,036 | | | 38,066 |
| | (13,030) |
Other (income) expense, net | | | (1,229) | | | 964 |
| | (2,193) | | | (78) | | | (629) |
| | 551 |
Income tax expense (benefit) | | | 46,801 | | | (18,846) |
| | 65,647 | |||||||||
Income tax expense | | | 11,636 | | | 30,404 |
| | (18,768) |
DerivativeDerivative(gain) loss, net – During the ninesix months ended SeptemberJune 30, 2023, the $40.1 million derivative gain recorded for crude oil and natural gas derivative contracts consists of $0.5 million of realized losses on settled contracts and $40.6 million of unrealized gains from the increase in the fair value of open contracts. During the six months ended June 30, 2022, the $109.9$71.1 million derivative loss recorded for crude oil and natural gas derivative contracts consistsconsisted of $96.3$36.0 million ofin realized lossesgains on settled contracts and premium amortization and $13.6 million of unrealized losses, net from the decrease in the fair value of open contracts. During the nine months ended September 30, 2021, the $179.2 million derivative loss recorded for crude oil and natural gas derivative contracts consists of $53.6 million in realized losses on settled contracts and $125.5$107.1 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.
35
In the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of strike prices on certain outstanding purchased calls covering the second half of 2022 through the first quarter of 2025. This transaction2025 by increasing the weighted-average strike prices. These transactions resulted in net cash proceeds of $105.3 million, through restriking exercise prices of outstanding purchased call options. As part of this monetization, the Company restructured its purchased call options on natural gas to increase the weighted-average strike price to $7.48 per Mmbtu from $3.78 per Mmbtu for the remainder of 2022, $7.50 per Mmbtu from $3.50 per Mmbtu for 2023, $6.13 per Mmbtu from $3.50 per Mmbtu for 2024, and $5.50 per Mmbtu from $3.50 per Mmbtu for the first quarter of 2025.million.
Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through April 2028, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Financial Statements – Note 8 –Derivative4 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information.
Interest expense, net – Interest expense, net was $54.9$25.0 million and $50.5$38.1 million for the ninesix months ended SeptemberJune 30, 20222023 and 2021,2022, respectively. The increasedecrease of $4.4$13.0 million in 20222023 is primarily due to the redemption of the 9.75% Senior Second Lien Notes which occurred in February 2023, lower interest expense on the lower outstanding principal balance of the Term Loan, and increased interest income.
Other (income) expense, net – During the nine months ended September 30, 2022, other income net, consists of non-recurring adjustments These decreases were partially offset by interest expense incurred on the 11.75% Senior Second Lien Notes issued in late January 2023.
32
Income tax expense (benefit) – Income tax expense for the ninesix months ended SeptemberJune 30, 2023 and June 30, 2022 was $46.8$11.6 million compared to an income tax benefit of $18.8and $30.4 million, duringrespectively. For the ninesix months ended SeptemberJune 30, 2021.2023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and adjustments to the valuation allowance. For the ninesix months ended SeptemberJune 30, 2022, and 2021, incomethe Company’s effective tax benefitrate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to ourthe valuation allowance. OurThe Company’s effective tax rate was 20.0%45.6% and 17.3%20.1% for the ninesix months ended SeptemberJune 30, 20222023 and 2021,2022, respectively.
As of SeptemberJune 30, 2022,2023, the valuation allowance on our deferred tax assets was $15.2$19.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 109 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.
36
Liquidity and Capital Resources
Liquidity Overview
Our primary liquidity needs are to refinance existing debt, fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our ARO obligations. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other borrowings, and expect to continue to do so in the future.
The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement. As of SeptemberJune 30, 2022,2023, we had $447.1$171.6 million cash on hand, and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. Additionally,We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares or our common stock from time to time. We believe our access to the equity markets from our “at-the-market” equity offering program, our reserve based lending currently available under our Credit Agreement, along with our cash position, will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment.
As of September 30, 2022, we had outstanding $552.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that mature on November 1, 2023. We have commenced discussions with potential lenders and institutional investors regarding a potential refinancing of all or a portion of the Senior Second Lien Notes prior to maturity, although there is no assurance as to the terms of any such refinancing or whether or when such refinancing will occur. We also may seek financings with longer tenors and market-based covenants to continue to provide working and potential acquisition capital as well as provide funding for refinancing of all or a portion of our Senior Second Lien Notes. The terms of such financings, which may replace or augment our Credit Agreement and refinance all or a portion of our Senior Second Lien Notes, may vary significantly from those under the Credit Agreement and our Senior Second Lien Notes. We may also consider using a portion of our cash balances to reduce the amount required to be refinanced. While the nearing maturity of the Senior Second Lien Notes creates risk with respect to our future liquidity, management believes that the actions being taken to fully repay the Senior Second Lien Notes, including from cash on hand of approximately $447 million, cash to be generated through operations, a refinancing transaction and from the proceeds of a potential equity sale of up to $100 million available under the ATM program, would allow us to repay the Senior Second Lien Notes prior to their maturity. However, there is no guarantee the Company will be successful in achieving these objectives.
Sources and Uses of Cash
| | | | | | | | | | | | | | | |||||||
| | Nine Months Ended September 30, | | | | Six Months Ended June 30, | | | |||||||||||||
|
| 2022 | | 2021 |
| | Change |
| 2023 | | 2022 |
| | Change | |||||||
| | (In thousands) | |||||||||||||||||||
| |||||||||||||||||||||
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| | (In thousands) | |||||||||||||||||||
Operating activities |
| $ | 326,851 | | $ | 111,291 | | $ | 215,560 |
| $ | 49,632 | | $ | 237,759 | | $ | (188,127) | |||
Investing activities | |
| (89,677) | |
| (12,406) | |
| (77,271) | |
| (34,538) | |
| (78,900) | |
| 44,362 | |||
Financing activities | |
| (35,843) | |
| 114,973 | |
| (150,816) | |
| (304,824) | |
| (26,934) | |
| (277,890) |
Operating activities – Net cash provided by operating activities increased $215.6decreased $188.1 million for the ninesix months ended SeptemberJune 30, 20222023 compared to the corresponding period in 2021.2022. This was primarily due to (i) the $206.9 million decrease in revenues, (ii) the $332.8$42.6 million increase in operating expenses, and (iii) derivative cash settlements payments of $4.4 million during the six months ended June 30, 2023 as compared to net derivative cash settlement receipts of $70.2 million during the six months ended June 30, 2022. The decrease in revenues was due to a decrease in realized prices for oil, NGL,NGLs and natural gas, revenues duringand to a lesser extent the ninedecrease in production volumes. During the six months ended SeptemberJune 30, 2022 as comparedderivative cash settlement receipts were due to the prior year period, and (ii) $105.3$105.3 million of net cash proceeds received related to the monetization of certain natural gas call contracts through restructuring of strike prices which occurred during the second quarter of 2022contracts.. The increase in revenue was primarily due to the increase in realized prices for oil, NGLs, and natural gas, and to a lesser extent, the increase in production volumes. Our combined average realized sales price per Boe increased by 76.8% for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021, which caused total revenues to increase $302.8 million.
3733
These increasesdecreases in operating cash flow were partially offset by (i) an increase in settlements of AROs which decreased operating cash flows $61.3 million as compared to $19.7 million for the nine months ended September 30, 2022 and 2021, respectively, and (ii) changes in operating assets and liabilities (excluding ARO settlements) which decreasedincreased operating cash flows by $13.2$6.1 million as compared to $43.3a decrease of $37.9 million for the ninesix months ended SeptemberJune 30, 2022, and 2021, respectively, primarily related to higherlower oil and natural gas receivables balances due to higherdecreased realized prices combined with higher payables and lower accounts payable and accrued liabilities balances.in the current period and (ii) decreased ARO settlements of $11.8 million during the six months ended June 30, 2023 as compared to $39.8 million during the six months ended June 30, 2022.
Investing activities – Net cash used in investing activities increased $77.3decreased $44.4 million for the ninesix months ended SeptemberJune 30, 20222023 compared to the corresponding period in 2021.2022. The increasedecrease was primarily due to the acquisition of properties for $51.5$47.6 million along with other increases in capital spending during the ninesix months ended SeptemberJune 30, 2022 compared to the same period in 2021.2022.
Financing activities– During the ninesix months ended SeptemberJune 30, 2022,2023, cash used in financing activities was $35.8 million, primarily due to principal payments on the Term Loan. Net cash providedincreased by financing activities was $115.0$277.9 million for the ninesix months ended SeptemberJune 30, 20212023 compared to the corresponding period in 2022. This was due to the redemption of the $552.5 million principal amount outstanding 9.75% Senior Second Lien Notes on February 8, 2023, which includedwas partially offset by the net cash proceeds of $270.8 million received from the Term Loanissuance of $206.8 million, offset by $11.8 million ofthe 11.75% Senior Second Lien Notes. Additionally, the principal paymentsrepayments on the Term Loan and repayment of $80.0 million of borrowings under the Credit Agreement.decreased by $5.8 million.
Derivative Financial Instruments – From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas. See Financial Statements – Note 84 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information about our derivative activities. The following table summarizes the historical results of our hedging activities:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, | ||||||||||||||||
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 | ||||||||
Crude Oil ($/Bbl): | | ��� |
|
| |
|
| |
|
| |
| | |
|
| |
|
| |
|
| |
|
Average realized sales price, before the effects of derivative settlements | | $ | 90.23 | | $ | 68.57 | | $ | 97.59 | | $ | 63.07 | | $ | 71.76 | | $ | 107.90 | | $ | 71.81 | | $ | 101.43 |
Effects of realized commodity derivatives | |
| (9.97) | |
| (12.55) | |
| (14.90) | |
| (8.72) | |
| — | |
| (18.22) | |
| — | |
| (17.47) |
Average realized sales price, including realized commodity derivatives | | $ | 80.26 | | $ | 56.02 | | $ | 82.69 | | $ | 54.35 | | $ | 71.76 | | $ | 89.68 | | $ | 71.81 | | $ | 83.96 |
Natural Gas ($/Mcf) | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Average realized sales price, before the effects of derivative settlements | | $ | 9.89 | | $ | 4.31 | | $ | 7.58 | | $ | 3.40 | | $ | 2.34 | | $ | 7.70 | | $ | 2.73 | | $ | 6.40 |
Effects of realized commodity derivatives | |
| (4.56) | |
| (1.49) | |
| 1.52 | |
| (0.55) | |
| (0.03) | |
| 10.17 | |
| (0.03) | |
| 4.63 |
Average realized sales price, including realized commodity derivatives | | $ | 5.33 | | $ | 2.82 | | $ | 9.10 | | $ | 2.85 | | $ | 2.31 | | $ | 17.87 | | $ | 2.70 | | $ | 11.03 |
(1) |
Excludes the effects of premium |
Income Taxes – For 2022, we2023, the Company does not expect 10% to 15% of ourowe any cash taxes. The Company made income tax expense to be cash taxes. We do not have any outstanding currentpayments of $2.2 million for federal and $0.3 million for state purposes, and has income taxes receivable of $1.7 million for federal and made $5.2$0.2 million in income tax payments duringfor state for the ninesix months ended SeptemberJune 30, 2022.2023. See Financial Statements – Note 109 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.
Employee Retention Credit – Under the Consolidated Appropriations Act of 2021, the Company recognized a $2.2 million Employee Retention Credit during the six months ended June 30, 2023, which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.
3834
Capital Expenditures
The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities. The following table presents our capital expenditures for exploration, development and other leasehold costs:
| | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Six Months Ended June 30, | ||||||||
|
| 2022 |
| 2021 |
| 2023 |
| 2022 | ||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
|
| (In thousands) |
| (In thousands) | ||||||||
Exploration(1) | | $ | 10,065 | | $ | 5,850 | | $ | 2,660 | | $ | 9,854 |
Development(1) | |
| 12,743 | |
| 5,660 | |
| 18,360 | |
| 9,186 |
Acquisitions of interests | |
| 51,474 | |
| 754 | |
| — | |
| 47,625 |
Seismic and other | |
| 7,158 | |
| 3,761 | |
| 1,979 | |
| 6,449 |
Investments in oil and gas property/equipment – accrual basis | | $ | 81,440 | | $ | 16,025 | | $ | 22,999 | | $ | 73,114 |
(1) | Reported geographically in the subsequent table. |
The following table presents our exploration and development capital expenditures geographically in the Gulf of Mexico:
| | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Six Months Ended June 30, | ||||||||
|
| 2022 |
| 2021 |
| 2023 |
| 2022 | ||||
|
| (In thousands) | ||||||||||
| | | | | | | ||||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
| ||||||||||||
|
| (In thousands) | ||||||||||
| | | | | | | ||||||
Conventional shelf (1) | | $ | 10,473 | | $ | 4,469 | | $ | 6,898 | | $ | 7,849 |
Deepwater | |
| 12,335 | |
| 7,041 | |
| 14,122 | |
| 11,191 |
Exploration and development capital expenditures – accrual basis | | $ | 22,808 | | $ | 11,510 | | $ | 21,020 | | $ | 19,040 |
(1) | Includes exploration and development capital expenditures in Alabama state waters. |
The capital expenditures are included within Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheets and recorded on an accrual basis. The capital expenditures reported within the Investing activities section of the Condensed Consolidated Statements of Cash Flows include adjustments to report cash payments related to capital expenditures. Our capital expenditures for the ninesix months ended SeptemberJune 30, 20222023 were financed by cash flow from operations and cash on hand.
Acquisitions – As described in Financial Statements – Note 4 – Acquisitions under Part I, Item 1 of this Quarterly Report,There were no acquisitions during the six months ended June 30, 2023. During the six months ended June 30, 2022, the Company acquired the working interest and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields on February 1, 2022 and April 1, 2022. After normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date to the respective close date), cash consideration of approximately $34.0 million and $17.5 million was paid to the sellers. The transaction was funded using cash on hand.
Asset Retirement Obligations – Each quarter, we review and revise our ARO estimates. Our ARO estimates as of SeptemberJune 30, 20222023 and December 31, 20212022 were $453.6$480.8 million and $424.5$466.4 million, respectively. The increase is primarily due to the acquisitionARO accretion and upward revisions of assets as described above.These increases wereestimates, partially offset by $61.3 million related to liabilities settled. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Risk Factors, under Part I, Item 1A of our 20212022 Annual Report for additional information.
3935
TVPX Transaction – On May 15, 2023, we acquired a corporate aircraft from a company affiliated with and controlled by our CEO. The purchase price of the aircraft was $19.1 million, which was paid using $9.0 million of cash on hand and through the assumption of the TVPX Loan, which had a fair market value of $10.1 million on the date of assumption. A valuation prepared by an independent third-party appraiser was one of the components used in determining the purchase price value. Factors considered for purchasing the aircraft were the primary use of making business travel efficient as well as our intent to charter out the aircraft to defray a portion of the operating costs and certain tax considerations and benefits. The terms of this transaction were reviewed and approved by the Audit Committee of the Company’s Board of Directors. See Note 2 – Debt and Note 12 – Related Party Transactions for additional information.
Drilling Activity
We did not drill any wells induring the ninesix months ended SeptemberJune 30, 2022.2023. During the ninesix months ended SeptemberJune 30, 2022, we completed the East Cameron 349 B-1 well (Cota). The Cota well is in the Monza Joint Venture Drilling Program. See Financial Statements – Note 6 –Joint Venture Drilling Program under Part I, Item 1 of this Quarterly Report for additional information.
Debt
TVPX Loan – On May 15, 2023, we acquired a corporate aircraft. In connection with the acquisition, the TVPX Loan was assumed by TVPX Aircraft Solutions Inc., not in its individual capacity but as owner trustee of the trust which holds title to the aircraft, a wholly owned indirect subsidiary of the Company, as the borrower. At the time of the assumption, the TVPX Loan had an aggregate principal amount of $11.8 million outstanding. The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued interest, which began on May 17, 2023, and a balloon payment of $8.0 million at the end of the loan term. The TVPX Loan is guaranteed by the Company on an unsecured basis. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.
Term Loan – As of SeptemberJune 30, 2022,2023, we had $157.0$128.7 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, which began September 30, 2021, bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers, and is not secured by any assets other than first lien security interests in the equity in the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of Subsidiary Borrowers (the Mobile Bay Properties). See Financial Statements – Note 2 –Debt– Debt under Part I, Item 1 of this Quarterly Report for additional information.
Credit Agreement – During the ninesix months ended SeptemberJune 30, 2022,2023, we had no borrowings incurred or outstanding under the Credit Agreement. On November 7, 2022, the Company entered into the Eleventh Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, , which extended the maturity date and Lender commitment to January 3, 2024, or in the event the
11.75% Senior Second Lien Notes are not refinanced or replaceddue 2026 – On January 27, 2023, we issued and sold $275 million in full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023
aggregate principal amount of our 11.75% Senior Second Lien Notes – As of September 30, 2022, we had outstanding $552.5 million principal of Senior Second Lien Notes at par with an interest rate of 9.75%11.75% per annum that maturematures on NovemberFebruary 1, 2023.2026. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. As of June 30, 2023, we had outstanding $275.0 million principal of 11.75% Senior Second Lien Notes. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.
36
9.75% Senior Second Lien Notes due 2023 – On February 8, 2023, we redeemed all of the 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes due 2026 and cash on hand of $296.1 million to fund the redemption. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.
Debt Covenants – The Term Loan, Credit Agreement and Senior Second Lien Notes containcontains financial covenants calculated as of the last day of each fiscal quarter, which includeincludes thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, Credit Agreement and the Indenture.Agreement. We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the Indenture as of and for the period ended SeptemberJune 30, 2022.2023. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.
40
The Subsidiary Borrowers
On May 19, 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries of W&T Offshore, Inc., through their parent, Aquasition Energy LLC (collectively, the “Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for the Term Loan in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by A-I LLC and A-II LLC to fund the acquisition of the Mobile Bay Properties and the Midstream Assets, respectively, from the Company. The Term Loan is non-recourse to the Company and any subsidiaries other than the Aquasition Entities and is secured by the first lien security interests in the equity of the Aquasition Entities and a first lien mortgage security interest in the Mobile Bay Properties.Loan. See Financial Statements – Note 5 – Subsidiary Borrowers under Part II,I, Item 1 in this Quarterly Report for additional information.
At that time, weWe designated the Aquasition Entities as unrestricted subsidiaries under the Indenture governing our Senior Second Lien Notes (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the 11.75% Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the Indenture. Under the Subsidiary Credit Agreement and related instruments, assets of the Aquasition Entities may not be available to mortgage or pledge as security to secure new indebtedness of the Company and its other subsidiaries. See Financial Statements – Note 2 – Debt under Part I, Item 1 in this Quarterly Report for additional information.
4137
Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Condensed Consolidated Balance Sheet as of SeptemberJune 30, 20222023 (in thousands):
| | | | | | | | | | | | | | | | | | |
| | Consolidated | | Eliminations of Unrestricted Subsidiaries | | Consolidated Balance Sheet of restricted subsidiaries | | Consolidated | | Eliminations of Unrestricted Subsidiaries | | Consolidated Balance Sheet of restricted subsidiaries | ||||||
Assets |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Current assets: |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Cash and cash equivalents | | $ | 447,130 | | $ | (54,219) | | $ | 392,911 | | $ | 171,627 | | $ | (5,899) | | $ | 165,728 |
Restricted cash | | | 4,417 | | | — | | | 4,417 | | | 4,417 | | | — | | | 4,417 |
Receivables: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Oil and natural gas sales | |
| 89,195 | |
| (80,431) | |
| 8,764 | |
| 41,342 | |
| (18,411) | |
| 22,931 |
Joint interest, net | |
| 16,815 | |
| 5,749 | |
| 22,564 | |
| 13,875 | |
| 27,400 | |
| 41,275 |
Income taxes | |
| 1,941 | |
| — | |
| 1,941 | |||||||||
Total receivables | |
| 106,010 | |
| (74,682) | |
| 31,328 | |
| 57,158 | |
| 8,989 | |
| 66,147 |
Prepaid expenses and other assets | |
| 53,014 | |
| (614) | |
| 52,400 | |
| 21,365 | |
| (125) | |
| 21,240 |
Total current assets | |
| 610,571 | |
| (129,515) | |
| 481,056 | |
| 254,567 | |
| 2,965 | |
| 257,532 |
| | | | | | | | | | |||||||||
Oil and natural gas properties and other, net | |
| 729,958 | |
| (280,444) | |
| 449,514 | |
| 737,740 | |
| (289,959) | |
| 447,781 |
| | | | | | | | | | |||||||||
Restricted deposits for asset retirement obligations | |
| 21,760 | |
| — | |
| 21,760 | |
| 22,092 | |
| — | |
| 22,092 |
Deferred income taxes | |
| 62,334 | |
| — | |
| 62,334 | |
| 45,700 | |
| — | |
| 45,700 |
Other assets | |
| 65,681 | |
| 19,438 | |
| 85,119 | |
| 42,118 | |
| (11,486) | |
| 30,632 |
Total assets | | $ | 1,490,304 | | $ | (390,521) | | $ | 1,099,783 | | $ | 1,102,217 | | $ | (298,480) | | $ | 803,737 |
Liabilities and Shareholders’ Equity (Deficit) | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Current liabilities: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Accounts payable | | $ | 75,068 | | $ | (49,859) | | $ | 25,209 | | $ | 70,403 | | $ | (8,996) | | $ | 61,407 |
Undistributed oil and natural gas proceeds | |
| 59,518 | |
| (22,077) | |
| 37,441 | |
| 31,178 | |
| (3,625) | |
| 27,553 |
Asset retirement obligations | |
| 54,886 | |
| — | |
| 54,886 | |
| 37,763 | |
| — | |
| 37,763 |
Accrued liabilities | |
| 154,236 | |
| (89,431) | |
| 64,805 | |
| 39,323 | |
| (19,036) | |
| 20,287 |
Current portion of long-term debt | | | 35,450 | | | (35,450) | | | — | | | 30,550 | | | (30,074) | | | 476 |
Income tax payable | |
| 1,613 | |
| — | |
| 1,613 | |
| 10 | |
| — | |
| 10 |
Total current liabilities | |
| 380,771 | |
| (196,817) | |
| 183,954 | |
| 209,227 | |
| (61,731) | |
| 147,496 |
Long-term debt | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Principal | |
| 674,031 | |
| (121,571) | |
| 552,460 | |
| 382,697 | |
| (97,222) | |
| 285,475 |
Unamortized debt issuance costs | |
| (8,058) | |
| 5,067 | |
| (2,991) | |
| (9,676) | |
| 2,304 | |
| (7,372) |
Long-term debt, net | |
| 665,973 | |
| (116,504) | |
| 549,469 | |
| 373,021 | |
| (94,918) | |
| 278,103 |
| | | | | | | | | | |||||||||
Asset retirement obligations, less current portion | |
| 398,724 | |
| (59,107) | |
| 339,617 | |
| 443,069 | |
| (66,136) | |
| 376,933 |
Other liabilities | |
| 99,740 | |
| (79,602) | |
| 20,138 | |
| 52,037 | |
| (22,020) | |
| 30,017 |
Deferred income taxes | |
| 113 | |
| — | |
| 113 | |
| 72 | |
| — | |
| 72 |
Common stock | |
| 1 | |
| — | |
| 1 | |
| 1 | |
| — | |
| 1 |
Shareholders' equity (deficit): | | | | | | | | | | |||||||||
Additional paid-in capital | |
| 557,386 | |
| — | |
| 557,386 | |
| 579,849 | |
| — | |
| 579,849 |
Retained deficit | |
| (588,237) | |
| 61,509 | |
| (526,728) | |
| (530,892) | |
| (53,675) | |
| (584,567) |
Treasury stock, at cost | |
| (24,167) | |
| — | |
| (24,167) | |
| (24,167) | |
| — | |
| (24,167) |
Total shareholders’ equity (deficit) | |
| (55,017) | |
| 61,509 | |
| 6,492 | |
| 24,791 | |
| (53,675) | |
| (28,884) |
Total liabilities and shareholders’ equity (deficit) | | $ | 1,490,304 | | $ | (390,521) | | $ | 1,099,783 | | $ | 1,102,217 | | $ | (298,480) | | $ | 803,737 |
4238
Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Condensed Consolidated Statement of Operations for the ninesix months ended SeptemberJune 30, 20222023 (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | Consolidated | | | Eliminations of Unrestricted Subsidiaries | | | Consolidated restricted subsidiaries | | | Consolidated Statement of Operations | | | Eliminations of Unrestricted Subsidiaries | | | Consolidated Statement of Operations of restricted subsidiaries |
Revenues: | | | | | | | | | | | | | | | | | | |
Oil | | $ | 412,526 | | $ | (710) | | $ | 411,816 | | $ | 186,982 | | $ | (288) | | $ | 186,694 |
NGLs | |
| 47,430 | |
| (28,541) | |
| 18,889 | |
| 18,180 | |
| (11,660) | |
| 6,520 |
Natural gas | |
| 257,452 | |
| (180,109) | |
| 77,343 | |
| 48,242 | |
| (32,354) | |
| 15,888 |
Other | |
| 13,889 | |
| (9,265) | |
| 4,624 | |
| 4,502 | |
| (2,258) | |
| 2,244 |
Total revenues | |
| 731,297 | |
| (218,625) | |
| 512,672 | |
| 257,906 | |
| (46,560) | |
| 211,346 |
Operating expenses: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Lease operating expenses | |
| 155,397 | |
| (37,350) | |
| 118,047 | |
| 131,207 | |
| (48,157) | |
| 83,050 |
Gathering, transportation and production taxes | | | 26,647 | | | (13,910) | | | 12,737 | | | 12,938 | | | (4,054) | | | 8,884 |
Depreciation, depletion, amortization and accretion | |
| 99,384 | |
| (619) | |
| 98,765 | |
| 66,028 | |
| 2,375 | |
| 68,403 |
General and administrative expenses | |
| 51,790 | |
| (1,082) | |
| 50,708 | |
| 37,312 | |
| (654) | |
| 36,658 |
Total operating expenses | |
| 333,218 | |
| (52,961) | |
| 280,257 | |
| 247,485 | |
| (50,490) | |
| 196,995 |
Operating income | |
| 398,079 | |
| (165,664) | |
| 232,415 | |
| 10,421 | |
| 3,930 | |
| 14,351 |
| | | | | | | | | | | | | | | | | | |
Interest expense, net | |
| 54,915 | |
| (11,841) | |
| 43,074 | |
| 25,036 | |
| (5,411) | |
| 19,625 |
Derivative loss (gain) | |
| 109,892 | |
| (187,896) | |
| (78,004) | |||||||||
Derivative (gain) loss, net | |
| (40,069) | |
| 52,389 | |
| 12,320 | |||||||||
Other income, net | |
| (1,229) | |
| (64) | |
| (1,293) | |
| (78) | |
| — | |
| (78) |
Income before income taxes | |
| 234,501 | |
| 34,009 | |
| 268,638 | |||||||||
Income tax benefit | |
| 46,801 | |
| — | |
| 46,801 | |||||||||
Net income | | $ | 187,700 | | $ | 34,009 | | $ | 221,837 | |||||||||
Income (loss) before income taxes | |
| 25,532 | |
| (43,048) | |
| (17,516) | |||||||||
Income tax expense | |
| 11,636 | |
| — | |
| 11,636 | |||||||||
Net (loss) income | | $ | 13,896 | | $ | (43,048) | | $ | (29,152) |
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Subsidiary Borrowers for the nine months ended September 30, 2022:periods indicated:
|
|
|
|
|
|
|
| |
|
| |
|
| |
|
| |
|
|
| | | | |
| | Six Months Ended June 30, | ||
Production Volumes: | | 2023 | | 2022 |
Oil (MBbls) |
| 7 |
| 7 |
NGLs (MBbls) |
| 465 |
| 468 |
Natural gas (MMcf) |
| 11,570 |
| 15,166 |
Total oil equivalent (MBoe) |
| 2,400 |
| 3,003 |
4339
Contractual Obligations
As of SeptemberJune 30, 2022,2023, there were no long-term drilling rig commitments. Except as disclosed herein, contractual obligations as of SeptemberJune 30, 20222023 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our 20212022 Annual Report.
Critical Accounting Policies and Estimates
We consider accounting policies related to revenue recognition, full cost accounting, impairment of oil and natural gas properties, provedoil and natural gas reserve estimates, fair value measure of financial instruments,quantities, asset retirement obligations, revenue recognition and income taxes as critical accounting policies. These policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used.
There have been no changes to our critical accounting policies which are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of our 20212022 Annual Report.
Recent Accounting Pronouncements
There waswere no recently issued accounting standards material to us.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about the types of market risks for the Septembersix months ended June 30, 20222023 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our 20212022 Annual Report. In addition, the information contained herein should be read in conjunction with the related disclosures in our 20212022 Annual Report.
Item 4. Controls and Procedures
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our CEO and CFO,Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), our CEO and CFO performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Quarterly Report. Based on that evaluation, our CEO and CFO have each concluded that as of SeptemberJune 30, 2022,2023, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
During the quarter ended SeptemberJune 30, 2022,2023, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
4440
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
See Financial Statements – Note 1211 – Contingencies under Part I Item 1 of this Quarterly Report for information on various legal proceedings to which we are a party or our properties are subject.
Item 1A. Risk Factors
As ofIn addition to the date ofinformation set forth in this Quarterly Report, except as described below,investors should carefully consider the risk factors and other cautionary statements included under Part I, Item 1A, Risk Factors, in our 2022 Annual Report, together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Notwithstanding the matters discussed herein, there have been no material changes toin our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our 20212022 Annual Report and in Part II, Item 1A, Risk Factors, in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2022 and June 30, 2022. The information presented below updates, and should be read in conjunction with, the risk factors referenced above.Report.
We outsource substantially all of our information technology infrastructure and the management and servicing of such infrastructure, which makes us more dependent upon third parties and exposed to related risks. We are in the process of transitioning substantially all of such infrastructure, which subjects us to increased costs and risks.
We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of such infrastructure to a limited number of third-party service providers. As a result, we rely on third parties that we do not control to ensure that our technology needs are sufficiently met, and cyber risks are effectively managed. This reliance has subjected us to certain cybersecurity risks arising from the loss of control over certain processes, including the potential misappropriation, destruction, corruption or unavailability of certain data and systems, such as confidential or proprietary information. As such, a failure of any of our information technology service providers to perform its management and operational duties securely and effectively may have a material adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run our business. We also have not had written agreements with our primary service provider, which exposed us to additional risks with respect to the systems and data outsourced to such provider.
In August 2022, our primary information technology service provider, AAIT, notified us of its intention to cease providing services to us by September 2, 2022. In response, we began the transition of these services and infrastructure to inside the Company or to other providers. In addition, we filed an action in state district court against AAIT and an affiliated service provider for a temporary restraining order, temporary injunction, and permanent injunction seeking, among other things, to restrain AAIT from ceasing to provide services to us until the transition process is complete. On September 14, 2022, a notice was filed to remove that state court action in District Court of Harris County, Texas to United States District Court for the Southern District of Texas. In connection with the foregoing, on September 16, 2022, we and AAIT mutually agreed to the terms of an agreed order issued by the court providing for a temporary injunction for a period of a minimum of 60 days from the date of the order and up to a maximum of 120 days at our option, during which AAIT would continue to provide information technology services to us and assist with the transition process. The agreed order also provided for the appointment by mutual agreement of the parties of Hon. Gregg J. Costa (Ret.) as an independent adjudicator to assist in adjudicating ongoing disputes between the parties. This transition process has, and may continue to, disrupt certain of our business operations. Any difficulties in completing such transition could impair our ability to monitor our production and accurately prepare our results of operations in a timely fashion. Although we have moved and are continuing to move certain services within the Company and are transitioning to new service providers and implementing agreements with such providers, such transition exposes us to additional risks, including increased costs, focus of management’s attention, disruptions to certain of our business operations and loss, damage to or unavailability of data or systems, which could have an adverse effect on our business and results of operations.
45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.
46
TableDuring the three months ended June 30, 2023, none of Contentsour directors or “officers” (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408(a) of Regulation S-K).
Item 6. Exhibits
Exhibit |
| Description |
|
|
|
|
| Second Amended and Restated Articles of Incorporation of W&T Offshore, Inc. |
3.2 | | |
| ||
| ||
|
| |
| | |
| | |
| | |
10.1 | |
41
| | |
10.2* | | |
| | |
10.3* | | |
| | |
10.4* | | |
| | |
10.5* | | |
| | |
10.6 | | |
| | |
10.7† | | |
| | |
31.1* |
| |
|
|
|
31.2* |
| |
|
|
|
32.1** |
| Section 906 Certification of Chief Executive Officer and Chief Financial Officer |
|
|
|
101.INS* |
| Inline XBRL Instance Document |
|
|
|
101.SCH* |
| Inline XBRL Schema Document |
|
|
|
101.CAL* |
| Inline XBRL Calculation Linkbase Document |
|
|
|
101.DEF* |
| Inline XBRL Definition Linkbase Document |
|
|
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101.LAB* |
| Inline XBRL Label Linkbase Document |
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101.PRE* |
| Inline XBRL Presentation Linkbase Document |
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104* |
| Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
* | Filed herewith. |
** | Furnished herewith. |
† | Certain schedules and similar attachments to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to furnish a supplemental copy of each such omitted schedule or similar attachment to the SEC upon request. |
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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 9, 2022.August 2, 2023.
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| W&T OFFSHORE, INC. | |
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| By: | /s/ |
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| Executive Vice President and Chief Financial Officer (Principal Financial Officer), duly authorized to sign on behalf of the registrant |
4843