UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________
FORM 10-Q
________________________________
(Mark One)
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20212022
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ 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 1-32167
________________________________
VAALCOEnergy,Inc.
(Exact name of registrant as specified in its charter)
________________________________
Delaware | 76-0274813 | |
incorporationororganization) | (I.R.S.Employer IdentificationNo.) | |
9800RichmondAvenue Suite 700 Houston, Texas |
| |
(
|
| |
|
| |
| (Zip code) | |
(713) 623-0801
(Registrant’sRegistrant’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 | EGY | New York Stock Exchange |
Common Stock | EGY | London 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 Exchange Act during the past 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 x☒ 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 x☒ 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 | ☐ | |||
|
|
|
| |||
|
| Smaller reporting company Emerging growth company |
|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨ ☐
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨☐ No x☒
VAALCOVAALCO ENERGY, INC. AND SUBSIDIARIES
Table of Contents
Unless
EXPLANATORY NOTE
On October 13, 2022, VAALCO Energy, Inc. (“VAALCO”) and VAALCO Energy Canada ULC (“AcquireCo”), an indirect wholly-owned subsidiary of VAALCO, completed the previously announced business combination involving TransGlobe Energy Corporation (“TransGlobe”) whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares (the “Arrangement”) and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to an arrangement agreement entered into by VAALCO, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”).
Although this Quarterly Report on Form 10-Q is filed after the completion of the Arrangement, unless otherwise specifically noted herein, information set forth herein only relates to the period as of and for the quarter and year-to-date periods ended September 30, 2022 and therefore does not include the information of TransGlobe for those periods. Accordingly, unless the context otherwise indicates, references to “VAALCO,” “the Company”, “we,” “our,” or “us” in this Quarterly Report on Form 10-Q are only references to VAALCO Energy, Inc., including its wholly-ownedwholly owned subsidiaries prior to the Arrangement and do not include TransGlobe and its subsidiaries.
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
VAALCO
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
As of September 30, 2021 | As of December 31, 2020 | As of September 30, 2022 | As of December 31, 2021 | |||||||||||
ASSETS | (in thousands) | (in thousands) | ||||||||||||
Current assets: | ||||||||||||||
Cash and cash equivalents | $ | 52,839 | $ | 47,853 | $ | 69,289 | $ | 48,675 | ||||||
Restricted cash | 81 | 86 | 203 | 79 | ||||||||||
Receivables: | ||||||||||||||
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented | 1,050 | 3,587 | ||||||||||||
Foreign income taxes receivable | 2,056 | — | ||||||||||||
Other | 86 | 4,331 | ||||||||||||
Trade, net | 16,781 | 22,464 | ||||||||||||
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented | 7,931 | 345 | ||||||||||||
Other, net | 12,190 | 9,977 | ||||||||||||
Crude oil inventory | 2,556 | 3,906 | 4,254 | 1,593 | ||||||||||
Prepayments and other | 5,416 | 4,215 | 12,616 | 5,156 | ||||||||||
Total current assets | 64,084 | 63,978 | 123,264 | 88,289 | ||||||||||
Crude oil and natural gas properties, equipment and other - successful efforts method, net | 74,102 | 37,036 | 194,711 | 94,324 | ||||||||||
Other noncurrent assets: | ||||||||||||||
Restricted cash | 1,752 | 925 | 1,755 | 1,752 | ||||||||||
Value added tax and other receivables, net of allowance of $5.8 million and $2.3 million, respectively | 5,670 | 4,271 | ||||||||||||
Value added tax and other receivables, net of allowance of $6.7 million and $5.7 million, respectively | 5,846 | 5,536 | ||||||||||||
Right of use operating lease assets | 12,984 | 22,569 | 1,705 | 10,227 | ||||||||||
Right of use finance lease assets | 1,630 | — | ||||||||||||
Deferred tax assets | 24,211 | — | 41,495 | 39,978 | ||||||||||
Abandonment funding | 22,281 | 12,453 | 18,838 | 21,808 | ||||||||||
Other long-term assets | 1,176 | — | 5,529 | 1,176 | ||||||||||
Total assets | $ | 206,260 | $ | 141,232 | $ | 394,773 | $ | 263,090 | ||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||
Current liabilities: | ||||||||||||||
Accounts payable | $ | 8,433 | $ | 16,690 | $ | 30,276 | $ | 18,797 | ||||||
Accounts with joint venture owners | 2,325 | 4,945 | — | 3,233 | ||||||||||
Accrued liabilities and other | 39,857 | 17,184 | 83,148 | 49,444 | ||||||||||
Operating lease liabilities - current portion | 12,671 | 12,890 | 1,200 | 9,642 | ||||||||||
Finance lease liabilities - current portion | 317 | — | ||||||||||||
Foreign income taxes payable | — | 860 | 28,056 | 3,128 | ||||||||||
Current liabilities - discontinued operations | 7 | 7 | 14 | 13 | ||||||||||
Total current liabilities | 63,293 | 52,576 | 143,011 | 84,257 | ||||||||||
Asset retirement obligations | 33,077 | 17,334 | 35,247 | 33,949 | ||||||||||
Operating lease liabilities - net of current portion | 312 | 9,671 | 521 | 587 | ||||||||||
Other long-term liabilities | — | 193 | ||||||||||||
Finance lease liabilities - net of current portion | 1,251 | — | ||||||||||||
Deferred tax liabilities | 41,057 | — | ||||||||||||
Total liabilities | 96,682 | 79,774 | 221,087 | 118,793 | ||||||||||
Commitments and contingencies (Note 10) |
|
| ||||||||||||
Shareholders’ equity: | ||||||||||||||
Preferred stock, $25 par value; 500,000 shares authorized, none issued | — | — | ||||||||||||
Common stock, $0.10 par value; 100,000,000 shares authorized, 69,528,100 and 67,897,530 shares issued, 58,588,777 and 57,531,154 shares outstanding, respectively | 6,953 | 6,790 | ||||||||||||
Preferred stock, $25 par value; 500,000 shares authorized, none issued | — | — | ||||||||||||
Common stock, $0.10 par value; 100,000,000 shares authorized, 70,125,626 and 69,562,774 shares issued, 59,068,105 and 58,623,451 shares outstanding, respectively | 7,013 | 6,956 | ||||||||||||
Additional paid-in capital | 76,346 | 74,437 | 78,500 | 76,700 | ||||||||||
Less treasury stock, 10,939,323 and 10,366,376 shares, respectively, at cost | (43,847) | (42,421) | ||||||||||||
Less treasury stock, 11,057,521 and 10,939,323 shares, respectively, at cost | (44,635 | ) | (43,847 | ) | ||||||||||
Retained earnings | 70,126 | 22,652 | 132,808 | 104,488 | ||||||||||
Total shareholders' equity | 109,578 | 61,458 | 173,686 | 144,297 | ||||||||||
Total liabilities and shareholders' equity | $ | 206,260 | $ | 141,232 | $ | 394,773 | $ | 263,090 | ||||||
See notes to condensed consolidated financial statements.
VAALCOVAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands, except per share amounts) | ||||||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 78,097 | $ | 55,899 | $ | 257,738 | $ | 142,696 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Production expense | 23,312 | 25,208 | 67,147 | 57,760 | ||||||||||||
FPSO demobilization | 8,867 | — | 8,867 | — | ||||||||||||
Exploration expense | 56 | 479 | 250 | 1,286 | ||||||||||||
Depreciation, depletion and amortization | 8,963 | 6,970 | 21,827 | 16,928 | ||||||||||||
General and administrative expense | 1,979 | 2,940 | 10,507 | 12,221 | ||||||||||||
Bad debt expense and other | 1,020 | 318 | 2,083 | 814 | ||||||||||||
Total operating costs and expenses | 44,197 | 35,915 | 110,681 | 89,009 | ||||||||||||
Other operating (expense) income, net | — | 46 | (5 | ) | (440 | ) | ||||||||||
Operating income | 33,900 | 20,030 | 147,052 | 53,247 | ||||||||||||
Other income (expense): | ||||||||||||||||
Derivative instruments gain (loss), net | 3,778 | (5,147 | ) | (37,522 | ) | (21,070 | ) | |||||||||
Interest (expense) income, net | (234 | ) | 3 | (355 | ) | 9 | ||||||||||
Other (expense) income, net | (7,707 | ) | (328 | ) | (10,514 | ) | 4,088 | |||||||||
Total other expense, net | (4,163 | ) | (5,472 | ) | (48,391 | ) | (16,973 | ) | ||||||||
Income from continuing operations before income taxes | 29,737 | 14,558 | 98,661 | 36,274 | ||||||||||||
Income tax expense (benefit) | 22,843 | (17,183 | ) | 64,467 | (11,272 | ) | ||||||||||
Income from continuing operations | 6,894 | 31,741 | 34,194 | 47,546 | ||||||||||||
Loss from discontinued operations, net of tax | (26 | ) | (20 | ) | (58 | ) | (72 | ) | ||||||||
Net income | $ | 6,868 | $ | 31,721 | $ | 34,136 | $ | 47,474 | ||||||||
Basic net income per share: | ||||||||||||||||
Income from continuing operations | $ | 0.12 | $ | 0.53 | $ | 0.57 | $ | 0.81 | ||||||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||
Net income per share | $ | 0.12 | $ | 0.53 | $ | 0.57 | $ | 0.81 | ||||||||
Basic weighted average shares outstanding | 59,068 | 58,586 | 58,900 | 58,102 | ||||||||||||
Diluted net income per share: | ||||||||||||||||
Income from continuing operations | $ | 0.11 | $ | 0.53 | $ | 0.57 | $ | 0.80 | ||||||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||
Net income per share | $ | 0.11 | $ | 0.53 | $ | 0.57 | $ | 0.80 | ||||||||
Diluted weighted average shares outstanding | 59,450 | 58,916 | 59,335 | 58,654 | ||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands, except per share amounts) | ||||||||||||
Revenues: | ||||||||||||
Crude oil and natural gas sales | $ | 55,899 | $ | 18,256 | $ | 142,696 | $ | 54,619 | ||||
Operating costs and expenses: | ||||||||||||
Production expense | 25,208 | 8,984 | 57,760 | 30,859 | ||||||||
Exploration expense | 479 | 16 | 1,286 | 16 | ||||||||
Depreciation, depletion and amortization | 6,970 | 2,212 | 16,928 | 8,116 | ||||||||
Impairment of proved crude oil and natural gas properties | 0 | 0 | 0 | 30,625 | ||||||||
General and administrative expense | 2,940 | 2,178 | 12,221 | 5,951 | ||||||||
Bad debt expense and other | 318 | 151 | 814 | 1,140 | ||||||||
Total operating costs and expenses | 35,915 | 13,541 | 89,009 | 76,707 | ||||||||
Other operating income (expense), net | 46 | (37) | (440) | (883) | ||||||||
Operating income (loss) | 20,030 | 4,678 | 53,247 | (22,971) | ||||||||
Other income (expense): | ||||||||||||
Derivative instruments gain (loss), net | (5,147) | — | (21,070) | 6,583 | ||||||||
Interest income, net | 3 | 23 | 9 | 150 | ||||||||
Other, net | (328) | 147 | 4,088 | 163 | ||||||||
Total other income (expense), net | (5,472) | 170 | (16,973) | 6,896 | ||||||||
Income (loss) from continuing operations before income taxes | 14,558 | 4,848 | 36,274 | (16,075) | ||||||||
Income tax expense (benefit) | (17,183) | (2,759) | (11,272) | 28,470 | ||||||||
Income (loss) from continuing operations | 31,741 | 7,607 | 47,546 | (44,545) | ||||||||
Income (loss) from discontinued operations, net of tax | (20) | 11 | (72) | (41) | ||||||||
Net income (loss) | $ | 31,721 | $ | 7,618 | $ | 47,474 | $ | (44,586) | ||||
Basic net income (loss) per share: | ||||||||||||
Income (loss) from continuing operations | $ | 0.53 | $ | 0.13 | $ | 0.81 | $ | (0.77) | ||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||
Net income (loss) per share | $ | 0.53 | $ | 0.13 | $ | 0.81 | $ | (0.77) | ||||
Basic weighted average shares outstanding | 58,586 | 57,456 | 58,102 | 57,628 | ||||||||
Diluted net income (loss) per share: | ||||||||||||
Income (loss) from continuing operations | $ | 0.53 | $ | 0.13 | $ | 0.80 | $ | (0.77) | ||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||
Net income (loss) per share | $ | 0.53 | $ | 0.13 | $ | 0.80 | $ | (0.77) | ||||
Diluted weighted average shares outstanding | 58,916 | 57,741 | 58,654 | 57,628 | ||||||||
See notes to condensed consolidated financial statements.
VAALCOVAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’SHAREHOLDERS’ EQUITY (Unaudited)
Common Shares Issued | Treasury Shares | Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings | Total | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Balance at January 1, 2022 | 69,562 | (10,939 | ) | $ | 6,956 | $ | 76,700 | $ | (43,847 | ) | $ | 104,488 | $ | 144,297 | ||||||||||||||
Shares issued - stock-based compensation | 300 | (64 | ) | 30 | 168 | — | — | 198 | ||||||||||||||||||||
Stock-based compensation expense | — | — | — | 404 | — | — | 404 | |||||||||||||||||||||
Treasury stock | — | — | — | — | (387 | ) | — | (387 | ) | |||||||||||||||||||
Dividend Distribution | — | — | — | — | — | (1,929 | ) | (1,929 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 12,164 | 12,164 | |||||||||||||||||||||
Balance at March 31, 2022 | 69,862 | (11,003 | ) | $ | 6,986 | $ | 77,272 | $ | (44,234 | ) | $ | 114,723 | $ | 154,747 | ||||||||||||||
Shares issued - stock-based compensation | 263 | (54 | ) | 27 | 31 | — | — | 58 | ||||||||||||||||||||
Stock-based compensation expense | — | — | — | 616 | — | — | 616 | |||||||||||||||||||||
Treasury stock | — | — | — | — | (401 | ) | — | (401 | ) | |||||||||||||||||||
Dividend Distribution | — | — | — | — | — | (1,943 | ) | (1,943 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 15,104 | 15,104 | |||||||||||||||||||||
Balance at June 30, 2022 | 70,125 | (11,057 | ) | $ | 7,013 | $ | 77,919 | $ | (44,635 | ) | $ | 127,884 | $ | 168,181 | ||||||||||||||
Shares issued - stock-based compensation | — | — | — | — | — | — | — | |||||||||||||||||||||
Stock-based compensation expense | — | — | — | 581 | — | — | 581 | |||||||||||||||||||||
Treasury stock | — | — | — | — | — | — | — | |||||||||||||||||||||
Dividend Distribution | — | — | — | — | — | (1,944 | ) | (1,944 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 6,868 | 6,868 | |||||||||||||||||||||
Balance at September 30, 2022 | 70,125 | (11,057 | ) | $ | 7,013 | $ | 78,500 | $ | (44,635 | ) | $ | 132,808 | $ | 173,686 | ||||||||||||||
Common Shares Issued | Treasury Shares | Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings | Total | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Balance at January 1, 2021 | 67,897 | (10,366 | ) | $ | 6,790 | $ | 74,437 | $ | (42,421 | ) | $ | 22,652 | $ | 61,458 | ||||||||||||||
Shares issued - stock-based compensation | 431 | (155 | ) | 43 | 304 | — | — | 347 | ||||||||||||||||||||
Stock-based compensation expense | — | — | — | 323 | — | — | 323 | |||||||||||||||||||||
Treasury stock | — | — | — | — | (403 | ) | — | (403 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 9,869 | 9,869 | |||||||||||||||||||||
Balance at March 31, 2021 | 68,328 | (10,521 | ) | $ | 6,833 | $ | 75,064 | $ | (42,824 | ) | $ | 32,521 | $ | 71,594 | ||||||||||||||
Shares issued - stock-based compensation | 1,092 | (314 | ) | 109 | 597 | — | — | 706 | ||||||||||||||||||||
Stock-based compensation expense | — | — | — | 117 | — | — | 117 | |||||||||||||||||||||
Treasury stock | — | — | — | — | (765 | ) | — | (765 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 5,884 | 5,884 | |||||||||||||||||||||
Balance at June 30, 2021 | 69,420 | (10,835 | ) | $ | 6,942 | $ | 75,778 | $ | (43,589 | ) | $ | 38,405 | $ | 77,536 | ||||||||||||||
Shares issued - stock-based compensation | 108 | (104 | ) | 11 | 241 | — | — | 252 | ||||||||||||||||||||
Stock-based compensation expense | — | — | — | 327 | — | — | 327 | |||||||||||||||||||||
Treasury stock | — | — | — | — | (258 | ) | — | (258 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 31,721 | 31,721 | |||||||||||||||||||||
Balance at September 30, 2021 | 69,528 | (10,939 | ) | $ | 6,953 | $ | 76,346 | $ | (43,847 | ) | $ | 70,126 | $ | 109,578 | ||||||||||||||
Common Shares Issued | Treasury Shares | Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings | Total | |||||||||||||
(in thousands) | |||||||||||||||||||
Balance at January 1, 2021 | 67,897 | (10,366) | $ | 6,790 | $ | 74,437 | $ | (42,421) | $ | 22,652 | $ | 61,458 | |||||||
Shares issued - stock-based compensation | 431 | (155) | 43 | 304 | — | — | 347 | ||||||||||||
Stock-based compensation expense | — | — | — | 323 | — | — | 323 | ||||||||||||
Treasury stock | — | — | — | — | (403) | — | (403) | ||||||||||||
Net income | — | — | — | — | — | 9,869 | 9,869 | ||||||||||||
Balance at March 31, 2021 | 68,328 | (10,521) | 6,833 | 75,064 | (42,824) | 32,521 | 71,594 | ||||||||||||
Shares issued - stock-based compensation | 1,092 | (314) | 109 | 597 | — | — | 706 | ||||||||||||
Stock-based compensation expense | — | — | — | 117 | — | — | 117 | ||||||||||||
Treasury stock | — | — | — | — | (765) | — | (765) | ||||||||||||
Net income | — | — | — | — | — | 5,884 | 5,884 | ||||||||||||
Balance at June 30, 2021 | 69,420 | (10,835) | 6,942 | 75,778 | (43,589) | 38,405 | 77,536 | ||||||||||||
Shares issued - stock-based compensation | 108 | (104) | 11 | 241 | — | — | 252 | ||||||||||||
Stock-based compensation expense | — | — | — | 327 | — | — | 327 | ||||||||||||
Treasury stock | — | — | — | — | (258) | — | (258) | ||||||||||||
Net income | — | — | — | — | — | 31,721 | 31,721 | ||||||||||||
Balance at September 30, 2021 | 69,528 | (10,939) | $ | 6,953 | $ | 76,346 | $ | (43,847) | $ | 70,126 | $ | 109,578 | |||||||
Common Shares Issued | Treasury Shares | Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings | Total | |||||||||||||
(in thousands) | |||||||||||||||||||
Balance at January 1, 2020 | 67,674 | (9,649) | $ | 6,767 | $ | 73,549 | $ | (41,429) | $ | 70,833 | $ | 109,720 | |||||||
Shares issued - stock-based compensation | 125 | — | 13 | (13) | — | — | — | ||||||||||||
Stock-based compensation expense | — | — | — | 145 | — | — | 145 | ||||||||||||
Treasury stock | — | (517) | — | — | (652) | — | (652) | ||||||||||||
Net loss | — | — | — | — | — | (52,800) | (52,800) | ||||||||||||
Balance at March 31, 2020 | 67,799 | (10,166) | 6,780 | 73,681 | (42,081) | 18,033 | 56,413 | ||||||||||||
Shares issued - stock-based compensation | 20 | — | 2 | (2) | — | — | — | ||||||||||||
Stock-based compensation expense | — | — | — | 60 | — | — | 60 | ||||||||||||
Treasury stock | — | (197) | — | — | (338) | — | (338) | ||||||||||||
Net income | — | — | — | — | — | 596 | 596 | ||||||||||||
Balance at June 30, 2020 | 67,819 | (10,363) | 6,782 | 73,739 | (42,419) | 18,629 | 56,731 | ||||||||||||
Shares issued - stock-based compensation | — | — | — | — | — | — | — | ||||||||||||
Stock-based compensation expense | — | — | — | 322 | — | — | 322 | ||||||||||||
Treasury stock | — | — | — | — | — | — | — | ||||||||||||
Net income | — | — | — | — | — | 7,618 | 7,618 | ||||||||||||
Balance at September 30, 2020 | 67,819 | (10,363) | $ | 6,782 | $ | 74,061 | $ | (42,419) | $ | 26,247 | $ | 64,671 | |||||||
See notes to condensed consolidated financial statements.
VAALCOVAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
| Nine Months Ended September 30, | ||||||||
2022 | 2021 | |||||||
(in thousands) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income | $ | 34,136 | $ | 47,474 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Loss from discontinued operations, net of tax | 58 | 72 | ||||||
Depreciation, depletion and amortization | 21,827 | 16,928 | ||||||
Bargain purchase gain | — | (7,651 | ) | |||||
Deferred taxes | 39,540 | (24,211 | ) | |||||
Unrealized foreign exchange loss (gain) | 914 | (342 | ) | |||||
Stock-based compensation | 2,300 | 2,098 | ||||||
Cash settlements paid on exercised stock appreciation rights | (805 | ) | (3,051 | ) | ||||
Derivative instruments loss, net | 37,522 | 21,070 | ||||||
Cash settlements paid on matured derivative contracts, net | (42,683 | ) | (10,189 | ) | ||||
Bad debt expense and other | 2,083 | 814 | ||||||
Other operating expense, net | 5 | 440 | ||||||
Operational expenses associated with equipment and other | 953 | 835 | ||||||
Change in operating assets and liabilities: | ||||||||
Trade receivables | 5,683 | 11,156 | ||||||
Accounts with joint venture owners | (11,118 | ) | (19 | ) | ||||
Other receivables | (2,904 | ) | 94 | |||||
Crude oil inventory | (2,661 | ) | 4,059 | |||||
Prepayments and other | (1,120 | ) | 1,081 | |||||
Value added tax and other receivables | (5,371 | ) | (1,339 | ) | ||||
Other noncurrent assets | (2,842 | ) | (1,176 | ) | ||||
Accounts payable | 4,129 | (9,686 | ) | |||||
Foreign income taxes receivable/payable | 24,928 | (2,916 | ) | |||||
Accrued liabilities and other | 25,182 | 1,252 | ||||||
Net cash provided by continuing operating activities | 129,756 | 46,793 | ||||||
Net cash used in discontinued operating activities | (57 | ) | (72 | ) | ||||
Net cash provided by operating activities | 129,699 | 46,721 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Property and equipment expenditures | (103,853 | ) | (8,459 | ) | ||||
Acquisition of crude oil and natural gas properties | — | (22,505 | ) | |||||
Net cash used in continuing investing activities | (103,853 | ) | (30,964 | ) | ||||
Net cash used in discontinued investing activities | — | — | ||||||
Net cash used in investing activities | (103,853 | ) | (30,964 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from the issuances of common stock | 257 | 1,305 | ||||||
Dividend distribution | (5,816 | ) | — | |||||
Treasury shares | (788 | ) | (1,426 | ) | ||||
Deferred financing costs | (1,535 | ) | — | |||||
Payments of finance lease | (193 | ) | — | |||||
Net cash used in continuing financing activities | (8,075 | ) | (121 | ) | ||||
Net cash used in discontinued financing activities | — | — | ||||||
Net cash used in financing activities | (8,075 | ) | (121 | ) | ||||
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | 17,771 | 15,636 | ||||||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD | 72,314 | 61,317 | ||||||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD | $ | 90,085 | $ | 76,953 | ||||
Nine Months Ended September 30, | ||||||
2021 | 2020 | |||||
(in thousands) | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||
Net income (loss) | $ | 47,474 | $ | (44,586) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Loss from discontinued operations, net of tax | 72 | 41 | ||||
Depreciation, depletion and amortization | 16,928 | 8,116 | ||||
Bargain purchase gain | (7,651) | — | ||||
Impairment of proved crude oil and natural gas properties | — | 30,625 | ||||
Other amortization | — | 181 | ||||
Deferred taxes | (24,211) | 26,972 | ||||
Unrealized foreign exchange gain | (342) | (60) | ||||
Stock-based compensation | 2,098 | (2,097) | ||||
Cash settlements paid on exercised stock appreciation rights | (3,051) | — | ||||
Derivative instruments (gain) loss, net | 21,070 | (6,583) | ||||
Cash settlements received (paid) on matured derivative contracts, net | (10,189) | 7,216 | ||||
Bad debt expense and other | 814 | 1,140 | ||||
Other operating loss, net | 440 | 83 | ||||
Operational expenses associated with equipment and other | 835 | 1,418 | ||||
Cash advance for other long-term assets | (1,176) | — | ||||
Change in operating assets and liabilities: | ||||||
Trade receivables | 11,156 | 8,255 | ||||
Accounts with joint venture owners | (19) | 8,642 | ||||
Other receivables | 94 | 1,333 | ||||
Crude oil inventory | 4,059 | 291 | ||||
Prepayments and other | 1,081 | (1,153) | ||||
Value added tax and other receivables | (1,339) | (919) | ||||
Accounts payable | (9,686) | (9,318) | ||||
Foreign income taxes receivable/payable | (2,916) | (6,875) | ||||
Accrued liabilities and other | 1,252 | (3,285) | ||||
Net cash provided by continuing operating activities | 46,793 | 19,437 | ||||
Net cash used in discontinued operating activities | (72) | (376) | ||||
Net cash provided by operating activities | 46,721 | 19,061 | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property and equipment expenditures | (8,459) | (22,317) | ||||
Acquisition of crude oil and natural gas properties | (22,505) | — | ||||
Net cash used in continuing investing activities | (30,964) | (22,317) | ||||
Net cash used in discontinued investing activities | — | — | ||||
Net cash used in investing activities | (30,964) | (22,317) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||
Proceeds from the issuances of common stock | 1,305 | — | ||||
Treasury shares | (1,426) | (990) | ||||
Net cash used in continuing financing activities | (121) | (990) | ||||
Net cash used in discontinued financing activities | — | — | ||||
Net cash used in financing activities | (121) | (990) | ||||
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | 15,636 | (4,246) | ||||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD | 61,317 | 59,124 | ||||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD | $ | 76,953 | $ | 54,878 | ||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)
Nine Months Ended September 30, | ||||||||
2022 | 2021 | |||||||
(in thousands) | ||||||||
Supplemental disclosure of cash flow information: | ||||||||
Income taxes paid in-kind with crude oil | $ | — | $ | 20,103 | ||||
Interest paid, net of amounts capitalized | $ | 401 | $ | — | ||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||
Property and equipment additions incurred but not paid at end of period | $ | 39,105 | $ | 4,607 | ||||
Recognition of right-of-use finance lease assets and liabilities | $ | 1,851 | $ | — | ||||
Asset Retirement Obligations | $ | — | $ | 14,564 | ||||
Nine Months Ended September 30, | ||||||
2021 | 2020 | |||||
(in thousands) | ||||||
Supplemental disclosure of cash flow information: | ||||||
Income taxes paid in-kind with crude oil | $ | 20,103 | $ | 8,738 | ||
Supplemental disclosure of non-cash investing and financing activities: | ||||||
Property and equipment additions incurred but not paid at end of period | $ | 4,607 | $ | 1,360 | ||
Recognition of right-of-use operating lease assets and liabilities | $ | — | $ | 1,478 | ||
Asset retirement obligations | $ | 14,564 | $ | 359 | ||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1.ORGANIZATION AND ACCOUNTING POLICIES
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,”“VAALCO” or the “Company”) is a Houston, Texas basedTexas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, the Company has production operations and conducts exploration and development activities in Gabon, West Africa. The Company also has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, the CompanyVAALCO has discontinued operations associated with activities in Angola, West Africa.
VAALCO’s
On October 13, 2022, the Company and VAALCO Energy Canada ULC (“AcquireCo”), an indirect wholly-owned subsidiary of the Company, completed the previously announced business combination involving TransGlobe Energy Corporation (“TransGlobe”), whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares (the “Arrangement”) and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to an arrangement agreement entered into by VAALCO, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”). Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in the Arab Republic of Egypt and Canada. The post-Arrangement company (the “Combined Company”) is a leading African-focused operator with a strong production and reserve base and a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. See Note 3 for further discussion regarding the Arrangement.
As of September 30, 2022 and prior to the completion of the Arrangement, the Company’s consolidated subsidiaries arewere VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, andVAALCO Energy, Inc. (UK Branch), VAALCO Energy (USA), Inc.Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC and VAALCO Energy Canada ULC, an unlimited liability company incorporated under the laws of the Province of Alberta and a wholly owned subsidiary of the Company.
These condensed consolidated financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.
These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K10-K for the year ended December 31, 2020, 2021, which includes a summary of the significant accounting policies.
With respect to the novel strain of coronavirus (“COVID-19”COVID-19”), the World Health Organization declared a global pandemic on March 11, 2020. The adverse economic effects of the COVID-19 outbreak materially decreased demand for crude oil based on the restrictionsduring 2021, and continuing in place by governments trying to curb the outbreak and changes in consumer behavior. This led to a significant global oversupply of crude oil and consequently a substantial decrease in crude oil prices in 2020.
In response to the oversupply of crude oil, global crude oil producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (“OPEC+”), reached agreement in April 2020 to cut crude oil production. Further, in connection with the OPEC+ agreement, the Minister of Hydrocarbons in Gabon requested that the Company reduce its production. In response to such request from the Minister of Hydrocarbons, between July 2020 and April 2021, the Company temporarily reduced production from the Etame Marin block. Currently, the Company’s production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022.
The Company considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used for preparation of the financial statements. As a result, the Company recognized a number of material charges during the three months ended March 31, 2020, including impairments to its capitalized costs for proved crude oil and natural gas properties and valuation allowances on its deferred tax assets. These are discussed further in the following notes. For the three and nine months ended September 30, 2021,2022, crude oil prices have improved, there have been no disruptions to operations since the beginning of the pandemic, global economic activity has steadily increased,experienced significant improvement and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, 0 additional charges or impairments were requiredHowever, during the second quarter of 2022 the BA.5 strain of the Omicron variant caused surges in infections worldwide. While COVID-19 related travel restrictions have gradually eased as governments and people continue to have increasing access to vaccines that help reduce the spread of COVID-19, new surges in infections and hospitalizations could alter the current environment. The significant decline in oil prices experienced in 2020 was, in part, due to disruptions in the threeworldwide economy due to the COVID-19 pandemic which quarantined people and restricted travel. To date the Company's operations have not been materially impacted by COVID-19, and worldwide we are seeing improving economic activity while managing the risk of a resurgence, but there can be no guarantees that COVID-19 will not have an impact on the Company or nineits operations.
In July 2021, the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries (collectively, "OPEC+") agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022. However, as a result of the recent decline in oil prices, on October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiative.
The average Brent crude oil price for the three months ended December 31, 2021, March 31, 2022, June 30, 2022 and September 30, 2021. The continued spread2022 was, $79 per barrel, $100 per barrel, $113 per barrel and $100 per barrel respectively.
During the nine months ended September 30, 2022, the Company noticed that the lead times associated with obtaining materials to support its operations and drilling activities has lengthened and, in some cases, prices for materials have increased. Management believes the ongoing war between Russia and Ukraine and its related impact on the global economy are causing supply chain issues and energy concerns in parts of COVID-19,the global economy. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.
While the current commodity price environment is still favorable and the Company has not experienced material disruptions to its operations as a result of COVID-19 or as result of other forces, including vaccine-resistant strains,the Russia/Ukraine conflict, affecting the global market, any emergence of a new variant or repeated deterioration infurther deteriorations of the global supply chain market may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil and natural gas pricesproperties.
Principles of consolidation – The accompanying condensed consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.
Use of estimates – The preparation of the Financial Statements in conformity with GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could resultdiffer from those estimates.
Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in additional adverse impacts onhighly liquid instruments with original maturities of three months or less at the Company’s resultsdate of operations, cash flows and financial position, including further asset impairments.purchase.
Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at September 30, 2021 2022 and 20202021 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in Gabon. Long-term amounts at September 30, 2021 2022 and 20202021 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”)FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows:flows.
As of September 30, | ||||||||
2022 | 2021 | |||||||
(in thousands) | ||||||||
Cash and cash equivalents | $ | 69,289 | $ | 52,839 | ||||
Restricted cash - current | 203 | 81 | ||||||
Restricted cash - non-current | 1,755 | 1,752 | ||||||
Abandonment funding | 18,838 | 22,281 | ||||||
Total cash, cash equivalents and restricted cash | $ | 90,085 | $ | 76,953 | ||||
As of September 30, | ||||||
2021 | 2020 | |||||
(in thousands) | ||||||
Cash and cash equivalents | $ | 52,839 | $ | 41,986 | ||
Restricted cash - current | 81 | 82 | ||||
Restricted cash - non-current | 1,752 | 925 | ||||
Abandonment funding | 22,281 | 11,885 | ||||
Total cash, cash equivalents and restricted cash | $ | 76,953 | $ | 54,878 | ||
The Company conducts regular abandonment studies from time to time to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” inon the condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 1210 for further discussion.
On February 28,2019, the Gabonese branch of anthe international commercial bank holding the abandonment funds in a U.S. dollar denominated account advised that the bank regulator required transfer of the funds to the Central Bank (“Central Bank”) for theAfrican Economic and Monetary Community of Central Africa (“CEMAC”), of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Company’s production sharing contract related to the Etame Marin block located offshore Gabon (“Etame Marin block PSC”) provides that these payments must be denominated in U.S. dollars. The newdollars and the CEMAC foreign currency regulations provide for the establishment of a U.S. dollar account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests until February 2021. As a result, the Company was not able to make the annual abandonment funding payments in 2019, and 2020 or 2021 totaling $2.9 million.$4.3 million, net to VAALCO based on the 2018 abandonment study. In February of 2021, the Bank of Central BankAfrican State (“BEAC”) authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”). The Company, workingWorking with Citibank, on March 12, 2021 the Company filed the application to open the account on March 12, 2021 and is currently is awaiting the approval of the account from the Central Bank. Accordingly, the Company was not able to make its funding payment in 2021. In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for the opening of U.S. dollars escrow accounts for the abandonment funds at BEAC. The Company is currently working with the extractive industry to formulate the agreements, which are expected to be finalized in 2022, that regulate these accounts. Accordingly, pursuant to Amendment No.5 to of the Etame Marin block PSC also provides that required these funds to be in U.S. dollars, once the eventaccount for the Gabonese bank fails for any reason to reimburse allU.S. dollars abandonment fund is open at BEAC the Company will resume its funding of the principalabandonment fund in compliance with the Etame PSC.
Accounts with joint venture owners – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and interest due,production expenditures made by the Company and other joint interest owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.as an operator.
Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production, and joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator, as well asand receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company.Company. Portions of the Company’s costs in Gabon (including the Company’s VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). Most of these receivables have payment terms of 30 days or less. The Company monitors the creditworthiness of the counterparties. Joint interest owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements.
The Company routinely assesses the recoverability of all material receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. When collectability is in doubt, the Company records an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of the condensed consolidated statements of operations.
As of September 30, 2021 and December 31, 2020,2022, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $14.4$19.2 million ($11.2 million, net to VAALCO). As of September 30, 2022, the exchange rate was XAF 669.4 = $1.00. As of December 31, 2021, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $14.5 million ($9.6 million, net to VAALCO) and $13.4 million ($4.5 million, net to VAALCO), respectively. The. As of December 31, 2021, the exchange rate was XAF 566.0578.2 = $1.00 and XAF 534.8 = $1.00 at September 30, 2021 and December 31, 2020 respectively. $1.00.The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other (expense) income, net” line item of the condensed consolidated statements of operations.
The following table provides a roll forward of the aggregate allowance for bad debt:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands) | ||||||||||||
Allowance for bad debt | ||||||||||||
Balance at beginning of period | $ | (5,575) | $ | (1,904) | $ | (2,273) | $ | (1,508) | ||||
Bad debt charge | (318) | (151) | (814) | (1,140) | ||||||||
Adjustment associated with reversal of allowance on Mutamba receivable | — | — | — | 593 | ||||||||
Adjustment associated with Sasol Acquisition | — | — | (2,879) | — | ||||||||
Foreign currency gain (loss) | 117 | — | 190 | — | ||||||||
Balance at end of period | $ | (5,776) | $ | (2,055) | $ | (5,776) | $ | (2,055) | ||||
Derivative Instruments and Hedging Activities
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Allowance for bad debt | ||||||||||||||||
Balance at beginning of period | $ | (6,389 | ) | $ | (5,575 | ) | $ | (5,741 | ) | $ | (2,273 | ) | ||||
Bad debt charge, net of receipts | (1,020 | ) | (318 | ) | (2,083 | ) | (814 | ) | ||||||||
Adjustment associated with Sasol Acquisition | — | — | — | (2,879 | ) | |||||||||||
Foreign currency gain (loss) | 355 | 117 | 770 | 190 | ||||||||||||
Balance at end of period | $ | (7,054 | ) | $ | (5,776 | ) | $ | (7,054 | ) | $ | (5,776 | ) | ||||
Other receivables, net – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company enters is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude-oil produced by the Company was not compatible with the crude-oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery needs and another contract with the refinery itself to deliver the crude oil hedging arrangements from timeto. Under the contract with the provider of the crude oil, the third-party provider is entitled to time in an effort to mitigatea selling price consistent with the effectsprice the Company receives under the terms of commodity price volatility and enhance the predictabilityEtame PSC for the delivery of cash flows relatingthe crude oil to the marketingrefinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s September 30, 2022 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $12.1 million for amounts due to the Company from the refinery for 130 MBbls delivered in August and September of 2022,a portion$6.7 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 65 MBbls purchased of our crude oil production. While these instruments mitigatefrom the cash flow risksupplier in August and a $6.1 million current liability included in the "Accrued liabilities and other" line item for amounts due to the oil supplier for 65 MBbls of future decreasescrude oil purchased in commodity prices, they may also curtail benefits from future increasesSeptember 2022.
Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value and represent the share of crude oil produced and stored on the FPSO, but unsold at the end of the period and crude oil purchased in commodity prices. order to comply with the domestic market needs of the Republic of Gabon.
The Company records balances resulting from commodity risk management activities
Prepayments and Other – Included in “Prepayments and other” line item of the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gainssheet for the nine months ended September 30, 2022 are $7.9 million of prepayments related to fixed assets.
Materials and losses from the changesupplies – Materials and supplies, which are included in the fair value of derivative instruments“Prepayments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net”other” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations. See Note 8balance sheet, are primarily used for further discussion.
Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participantsproduction related activities. These assets are valued at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based onlower of cost, determined by the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:weighted-average method, or net realizable value.
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 14 for further discussion.
Fair value of financial instruments – The Company’s assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable, SARs and guarantees. As discussed above, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to the Company’s other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were 0 transfers between levels for the nine months ended September 30, 2021 and 2020.
As of September 30, 2021 | |||||||||||||
Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||
(in thousands) | |||||||||||||
Liabilities | |||||||||||||
SARs liability | Accrued liabilities | $ | — | $ | 761 | $ | — | $ | 761 | ||||
Derivative liability - crude oil swaps | Accrued liabilities | — | 10,881 | — | 10,881 | ||||||||
$ | — | $ | 11,642 | $ | — | $ | 11,642 | ||||||
As of December 31, 2020 | |||||||||||||
Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||
(in thousands) | |||||||||||||
Liabilities | |||||||||||||
SARs liability | Accrued liabilities | $ | — | $ | 2,289 | $ | — | $ | 2,289 | ||||
SARs liability | Other long-term liabilities | — | 193 | — | 193 | ||||||||
$ | — | $ | 2,482 | $ | — | $ | 2,482 | ||||||
Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil and natural gas producing activities. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results. See Note 7 for further discussion.
Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (i)(a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii)(b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block level basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are calculatedprovided on a block level basis under the unit-of-production method based upon estimates of proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil and natural gas producing activities, as well as property, plant and equipment unrelated to crude oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically three to five years for office and miscellaneous equipment and five to seven years for leasehold improvements.See Note 7 for further discussion.
Impairment– The Company reviews the crude oil and natural gas producing properties for impairment on a block level basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 (as defined in the policy "Fair value" below) inputs that are based upon estimates;estimates the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating
underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and in Block P in Equatorial Guinea. See Note 7 for further discussion.
Purchase Accounting – On February 25,2021, VAALCO Gabon S.A., a wholly owned subsidiary of the Company, completed the acquisition of Sasol Gabon S.A.’s (“Sasol’s”) 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the sale and purchase agreement (“SPA”) dated November 17,2020 (the “Sasol Acquisition”). The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired, and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.
Lease commitments– The Company leases office space, marine vesselsAt inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, if a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and helicopters, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expirea lease liability at various times. Allthe present value of the future lease payments. ROU assets for operating leases are characterized asrecorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and the expense is included in either “production expense” or “general and administrative expense” in“Operating lease liabilities – net of current portion” within the condensed consolidated financial statements. See Note 11balance sheets. ROU assets for further discussion.financing leases are recorded within “Right of use finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Finance lease liabilities – current portion” and “Finance lease liabilities – net of current portion” within the condensed consolidated balance sheets.
Asset retirement obligations (“ARO”(“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the crude oil and natural gas properties. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability is adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of the capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities. The Company accrues a liability with respect to these obligations based on its estimatefacilities, while accretion escalates over the lives of the timing and amountassets to replace, remove or retirereach the associated assets. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Depreciation, depletion and amortization” in the Company’s condensed consolidated statements of operations. See Note 12 for disclosures regarding the asset retirement obligations.expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 1213 for further discussion.
Revenue recognition –Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPA”). agreements. There is a single performance obligation (delivering crude oil to the delivery point, i.e., the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame Marin block PSC is not a customer contract. The terms of the Etame Marin block PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of “Profit Oil” (as defined in the Etame Marin block PSC) determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026)2026) for all costs. For both royalties and Profit Oil, the Etame Marin block PSC provides that the government of Gabon may settle these obligations in-kind, i.e., taking crude oil barrels, rather than with cash payments. See Note 6 for further discussion.
Income taxes
Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.
Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 15 for further discussion.
Income taxes – The annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the Company’sannual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the Company’s level of operations or profitability in each jurisdiction would impact the Company’s tax liability in any given year.
The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the Company’s income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The CompanyWe also recordsrecord as income tax expense the increase or decrease in the value of the government of Gabon’sgovernment’s allocation of Profit Oil which results due to changechanges in value from the time the obligationallocation is originally produced to the time the obligationallocation is actually paid or satisfied through lifting.lifted.
Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-notmore-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of net operating loss carry forwards or foreign tax credit carryovers.
In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the Company’s expectations change regarding the expected future tax consequences, it the Company may be required to record additional deferred taxes that could have a material effect on the Company’scondensed consolidated financial position and results of operations. See Note 1516 for further discussion.
Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations. See Note 8 for further discussion.
Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the internally developed present value of future cash flows model that underlies the fair-value measurement).
Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil and natural gas properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon our review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.
Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. With respect to the other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments.
As of September 30, 2022 | |||||||||||||||||
Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(in thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Derivative asset | Prepayments and other | $ | — | $ | 348 | $ | — | $ | 348 | ||||||||
| $ | — | $ | 348 | $ | — | $ | 348 | ||||||||||
Liabilities | |||||||||||||||||
SARs liability | Accrued liabilities and other | $ | — | $ | 544 | $ | — | $ | 544 | ||||||||
| $ | — | $ | 544 | $ | — | $ | 544 | ||||||||||
As of December 31, 2021 | |||||||||||||||||
Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (in thousands) | |||||||||||||||||
Liabilities | |||||||||||||||||
SARs liability | Accrued liabilities and other | $ | — | $ | 609 | $ | — | $ | 609 | ||||||||
Derivative liability | Accrued liabilities and other | — | 4,806 | — | 4,806 | ||||||||||||
| $ | — | $ | 5,415 | $ | — | $ | 5,415 | ||||||||||
Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.
2.NEW ACCOUNTING STANDARDS
Not Yet Adopted
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, 2016-13,Financial Instruments – Credit Losses (Topic 326)326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-132016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU No. 2019-042019-04 (“ASU 2019-04”2019-04”): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU No. 2019-05 (“2019-05 (“ASU 2019-05”2019-05”): Financial Instruments-Credit Losses (Topic 326)326) - Targeted Transition Relief. ASU 2019-042019-04 and ASU 2019-052019-05 provide certain codification improvements related to implementation of ASU 2016-132016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU No. 2019-10, 2019-10,Financial Instruments—Instruments—Credit Losses (Topic 326)326), Derivatives and Hedging (Topic 815)815), and Leases (Topic 842)842): Effective Dates. This amendment deferred the effective date of ASU No. 2016-132016-13 from January 1, 2020 to January 1, 2023 for calendar year end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13,2016-13, and related updates, until January 2023.
Adopted
In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2019-12, Income Taxes (Topic 740: Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which removes certain exceptions to the general principles in Topic 740. ASU 2019-12 is effective for the fiscal years beginning after December 15, 2020, with early adoption permitted. The adoption of this guidance did Company does not have expect a material impact on the Company's financial statements.adoption.
3. ACQUISITIONS AND DISPOSITIONS
TransGlobe Merger
On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding common shares of TransGlobe and TransGlobe became a direct wholly owned subsidiary of AcquireCo and an indirect wholly owned subsidiary of the Company pursuant to an arrangement agreement entered into by the Company, AcquireCo and TransGlobe on July 13, 2022.
At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive 0.6727 (the “exchange ratio”) of a share of common stock, par value $0.10 per share, of the Company (“VAALCO common stock,” and each share of VAALCO common stock, a “VAALCO share”). The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. The Arrangement resulted in VAALCO stockholders owning approximately 54.5%, and TransGlobe shareholders owning approximately 45.5% of the Combined Company, calculated based on vested outstanding shares of each company as of the date of the Arrangement Agreement. The Combined Company results of operations of VAALCO and TransGlobe for the fourth quarter of 2022 will be included in the Company’s consolidated results for the period ending December 31, 2022.
Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in the Arab Republic of Egypt and Canada. The Combined Company is a leading African-focused operator with a strong production and reserve base and a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. The transaction qualifies as a business combination under ASC 805, Business Combinations and the Company is the accounting acquiror. The purchase accounting for the business combination has not been completed.
For the three and nine months ended September 30, 2022 included in the line item "Other (expense) income, net" is $6.4 million and $7.6 million of transactions costs, respectively, associated with the Arrangement with TransGlobe.
Acquisition of Sasol Gabon S.A.’s’s Interest in Etame
On February 25,2021, VAALCO Gabon S.A. completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1,2020. Prior to the Sasol Acquisition, the Company owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased the Company’s working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations
increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February 25,2021.
The following amounts represent the preliminary allocation of the purchase price to the assets acquired and liabilities assumed in the Sasol Acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the acquisition. The final determination of fair value for certain assets and liabilities (VAT and accrued liabilities) could differ materially from the amounts set forth below:
February 25, 2021 | ||||
(in thousands) | ||||
Purchase Consideration | ||||
Cash | $ | 33,959 | ||
Fair value of contingent consideration | 4,647 | |||
Total purchase consideration | $ | 38,606 | ||
February 25, 2021 | ||||
(in thousands) | ||||
Assets acquired: | ||||
Wells, platforms and other production facilities | $ | 37,176 | ||
Equipment and other | 5,568 | |||
Value added tax and other receivables | 1,234 | |||
Abandonment funding | 11,781 | |||
Accounts receivable - trade | 11,220 | |||
Other current assets | 3,963 | |||
Liabilities assumed: | ||||
Asset retirement obligations | (14,564 | ) | ||
Accrued liabilities and other | (10,121 | ) | ||
Bargain purchase gain | (7,651 | ) | ||
Total purchase price | $ | 38,606 | ||
| ||
| ||
| ||
|
|
|
|
| |
|
|
|
| ||
| ||
| ||
|
|
|
|
| |
|
| |
|
| |
|
| |
|
| |
| ||
|
| |
|
| |
|
| |
|
|
|
All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, February 25, 2021, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The Company has had one year from the date of closing to record purchase price adjustments as a result of changes in such estimates. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed a $7.7 million bargain purchase gain was recognized. A bargain purchase gain of $5.5 million is included in “Other net”(expense) income, net" under “"Other income (expense)”" in the2021 condensed consolidated statements of operations. An income tax benefit of $2.2 million, related to the bargain purchase gain, is also included in the 2021condensed consolidated statements of operations.
The bargain purchase gain is primarily attributable to the increase in crude oil price forecasts from the date the SPA was signed, November 17, 2020, to the closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.
The impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $36.9 million and $121.6 million for the three and nine months ended September 30, 2022, respectively, and $3.3 million and $16.1 million increase to “Net income” in the condensed consolidated statements of operations for the three and nine months ended September 30, 2022, respectively.
The impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $26.4 million and $58.0and$58.0 million for the three and nine months ended September 30, 2021, respectively, and $10.2 million and $20.1 million increase to “Net income” in the condensed consolidated statements of operations for the three and nine months ended September 30, 2021, respectively.
The unaudited pro forma results presented below have been prepared to give the effect to the Sasol Acquisition discussed above on the Company’s results of operations for the three and nine months ended September 30, 2021 and 2020,, respectively, as if the Sasol Acquisition had been consummated on January 1, 2020. The unaudited pro forma results do not purport to represent what the Company’s actual results operations would have been if the Sasol Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands) | ||||||||||||
Pro forma (unaudited) | ||||||||||||
Crude oil and natural gas sales | $ | 55,899 | $ | 34,568 | $ | 160,469 | $ | 103,422 | ||||
Operating income (loss) | 20,030 | 7,750 | 63,929 | (12,481) | ||||||||
Net income (loss) | 31,721 | 9,136 | 49,341 | (a) | (36,316) | (b) | ||||||
Basic net income (loss) per share: | ||||||||||||
Income (loss) from continuing operations | $ | 0.53 | $ | 0.16 | $ | 0.85 | $ | (0.63) | ||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||
Net income (loss) per share | $ | 0.53 | $ | 0.16 | $ | 0.85 | $ | (0.63) | ||||
Basic weighted average shares outstanding | 58,586 | 57,456 | 58,102 | 57,628 | ||||||||
Diluted net income (loss) per share: | ||||||||||||
Income (loss) from continuing operations | $ | 0.53 | $ | 0.16 | $ | 0.84 | $ | (0.63) | ||||
Loss from discontinued operations, net of tax | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||
Net income (loss) per share | $ | 0.53 | $ | 0.16 | $ | 0.84 | $ | (0.63) | ||||
Diluted weighted average shares outstanding | 58,916 | 57,741 | 58,654 | 57,628 | ||||||||
(a) | The pro forma net income for the nine months ended September 30, 2021 excludes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $7.7 million and transaction costs of $1.0 million. |
________________
(a)The pro forma net income for the nine months ended September 30, 2021 excludes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $7.7 million and transaction costs of $1.0 million.
(b)The pro forma net loss for the nine months ended September 30, 2020 includes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $7.7 million and transaction costs of $1.0 million.
Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1,2020 to June 30,2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, the Company paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.
Discontinued Operations - Angola
In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s condensed consolidated statements of operations. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s condensed consolidated statements of cash flows. During the three and nine months ended September 30, 2021 2022 and 20202021, the Angola segment did not have a material impact on the Company’sfinancial position, results of operations, cash flows and related disclosures.disclosures.
4. SEGMENT INFORMATION
The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s 2 two reportable operating segments is organized and managed based upon geographic location. TheThe Company’s Chief Executive Officer, who is the chief operating decision maker, and management review and evaluate the operation of each geographic segment separately, primarily based on operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments.
Segment activity of continuing operations for the three and nine months ended September 30, 2021 2022 and 20202021 as well as long-lived assets and segment assets at September 30, 20212022 and December 31, 2020 2021 are as follows:
Three Months Ended September 30, 2022 | ||||||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 78,097 | $ | — | $ | — | $ | 78,097 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Production expense | 22,828 | 484 | — | 23,312 | ||||||||||||
FPSO demobilization | 8,867 | — | — | 8,867 | ||||||||||||
Exploration expense | 56 | — | — | 56 | ||||||||||||
Depreciation, depletion and amortization | 8,940 | — | 23 | 8,963 | ||||||||||||
General and administrative expense | 915 | 120 | 944 | 1,979 | ||||||||||||
Bad debt expense and other | 681 | 339 | — | 1,020 | ||||||||||||
Total operating costs and expenses | 42,287 | 943 | 967 | 44,197 | ||||||||||||
Other operating expense, net | — | — | — | — | ||||||||||||
Operating income | 35,810 | (943 | ) | (967 | ) | 33,900 | ||||||||||
Other income (expense): | ||||||||||||||||
Derivative instruments loss, net | — | — | 3,778 | 3,778 | ||||||||||||
Interest (expense) income, net | (351 | ) | — | 117 | (234 | ) | ||||||||||
Other (expense) income, net | (1,305 | ) | 1 | (6,403 | ) | (7,707 | ) | |||||||||
Total other expense, net | (1,656 | ) | 1 | (2,508 | ) | (4,163 | ) | |||||||||
Income from continuing operations before income taxes | 34,154 | (942 | ) | (3,475 | ) | 29,737 | ||||||||||
Income tax (benefit) expense | 25,415 | — | (2,572 | ) | 22,843 | |||||||||||
Income from continuing operations | 8,739 | (942 | ) | (903 | ) | 6,894 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (26 | ) | (26 | ) | ||||||||||
Net income | $ | 8,739 | $ | (942 | ) | $ | (929 | ) | $ | 6,868 | ||||||
Consolidated capital expenditures | $ | 51,610 | $ | — | $ | 53 | $ | 51,663 | ||||||||
Three Months Ended September 30, 2021 | ||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Revenues-crude oil and natural gas sales | $ | 55,899 | $ | — | $ | — | $ | 55,899 | ||||
Depreciation, depletion and amortization | 6,953 | — | 17 | 6,970 | ||||||||
Operating income (loss) | 22,834 | (271) | (2,533) | 20,030 | ||||||||
Derivative instruments loss, net | — | — | (5,147) | (5,147) | ||||||||
Income tax expense (benefit) | 436 | — | (17,619) | (17,183) | ||||||||
Additions to crude oil and natural gas properties and equipment – accrual | 6,696 | — | — | 6,696 | ||||||||
Nine Months Ended September 30, 2021 | ||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Revenues-crude oil and natural gas sales | $ | 142,696 | $ | — | $ | — | $ | 142,696 | ||||
Depreciation, depletion and amortization | 16,860 | — | 68 | 16,928 | ||||||||
Bad debt expense and other | 814 | — | — | 814 | ||||||||
Other operating expense, net | (440) | — | — | (440) | ||||||||
Operating income (loss) | 64,933 | (505) | (11,181) | 53,247 | ||||||||
Derivative instruments loss, net | — | — | (21,070) | (21,070) | ||||||||
Other, net | 7,207 | (2) | (3,117) | 4,088 | ||||||||
Income tax expense (benefit) | 8,396 | 1 | (19,669) | (11,272) | ||||||||
Additions to crude oil and natural gas properties and equipment – accrual | 10,993 | — | — | 10,993 | ||||||||
Three Months Ended September 30, 2020 | ||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Revenues-crude oil and natural gas sales | $ | 18,256 | $ | — | $ | — | $ | 18,256 | ||||
Depreciation, depletion and amortization | 1,946 | — | 266 | 2,212 | ||||||||
Bad debt expense and other | 151 | — | — | 151 | ||||||||
Operating income (loss) | 6,957 | (95) | (2,184) | 4,678 | ||||||||
Income tax expense (benefit) | (2,464) | 1 | (296) | (2,759) | ||||||||
Additions to crude oil and natural gas properties and equipment – accrual | (306) | — | (9) | (315) | ||||||||
Nine Months Ended September 30, 2020 | ||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Revenues-crude oil and natural gas sales | $ | 54,619 | $ | — | $ | — | $ | 54,619 | ||||
Depreciation, depletion and amortization | 7,790 | — | 326 | 8,116 | ||||||||
Impairment of proved crude oil and natural gas properties | 30,625 | — | — | 30,625 | ||||||||
Bad debt expense and other | 1,140 | — | — | 1,140 | ||||||||
Other operating expense, net | (883) | — | — | (883) | ||||||||
Operating loss | (17,622) | (289) | (5,060) | (22,971) | ||||||||
Derivative instruments gain, net | — | — | 6,583 | 6,583 | ||||||||
Income tax expense | 19,302 | 1 | 9,167 | 28,470 | ||||||||
Additions to crude oil and natural gas properties and equipment – accrual | 10,305 | — | (9) | 10,296 | ||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Long-lived assets from continuing operations: | ||||||||||||
As of September 30, 2021 | $ | 63,966 | $ | 10,000 | $ | 136 | $ | 74,102 | ||||
As of December 31, 2020 | $ | 26,832 | $ | 10,000 | $ | 204 | $ | 37,036 | ||||
Nine Months Ended September 30, 2022 | ||||||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 257,738 | $ | — | $ | — | $ | 257,738 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Production expense | 66,269 | 878 | — | 67,147 | ||||||||||||
FPSO demobilization | 8,867 | — | — | 8,867 | ||||||||||||
Exploration expense | 250 | — | — | 250 | ||||||||||||
Depreciation, depletion and amortization | 21,766 | — | 61 | 21,827 | ||||||||||||
General and administrative expense | 2,073 | 329 | 8,105 | 10,507 | ||||||||||||
Bad debt expense and other | 1,744 | 339 | — | 2,083 | ||||||||||||
Total operating costs and expenses | 100,969 | 1,546 | 8,166 | 110,681 | ||||||||||||
Other operating expense, net | (5 | ) | — | — | (5 | ) | ||||||||||
Operating income | 156,764 | (1,546 | ) | (8,166 | ) | 147,052 | ||||||||||
Other income (expense): | ||||||||||||||||
Derivative instruments loss, net | — | — | (37,522 | ) | (37,522 | ) | ||||||||||
Interest (expense) income, net | (515 | ) | — | 160 | (355 | ) | ||||||||||
Other (expense) income, net | (2,799 | ) | (1 | ) | (7,714 | ) | (10,514 | ) | ||||||||
Total other expense, net | (3,314 | ) | (1 | ) | (45,076 | ) | (48,391 | ) | ||||||||
Income from continuing operations before income taxes | 153,450 | (1,547 | ) | (53,242 | ) | 98,661 | ||||||||||
Income tax (benefit) expense | 74,671 | 1 | (10,205 | ) | 64,467 | |||||||||||
Income from continuing operations | 78,779 | (1,548 | ) | (43,037 | ) | 34,194 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (58 | ) | (58 | ) | ||||||||||
Net income | $ | 78,779 | $ | (1,548 | ) | $ | (43,095 | ) | $ | 34,136 | ||||||
Consolidated capital expenditures | $ | 121,492 | $ | — | $ | 120 | $ | 121,612 | ||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||
Total assets from continuing operations: | ||||||||||||
As of September 30, 2021 | $ | 149,188 | $ | 10,430 | $ | 46,642 | $ | 206,260 | ||||
As of December 31, 2020 | $ | 101,399 | $ | 10,267 | $ | 29,566 | $ | 141,232 | ||||
Three Months Ended September 30, 2021 | ||||||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 55,899 | $ | — | $ | — | $ | 55,899 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Production expense | 24,967 | 229 | 12 | 25,208 | ||||||||||||
Exploration expense | 479 | — | — | 479 | ||||||||||||
Depreciation, depletion and amortization | 6,953 | — | 17 | 6,970 | ||||||||||||
General and administrative expense | 394 | 42 | 2,504 | 2,940 | ||||||||||||
Bad debt expense and other | 318 | — | — | 318 | ||||||||||||
Total operating costs and expenses | 33,111 | 271 | 2,533 | 35,915 | ||||||||||||
Other operating expense, net | 46 | — | — | 46 | ||||||||||||
Operating income | 22,834 | (271 | ) | (2,533 | ) | 20,030 | ||||||||||
Other income (expense): | ||||||||||||||||
Derivative instruments loss, net | — | — | (5,147 | ) | (5,147 | ) | ||||||||||
Interest (expense) income, net | — | — | 3 | 3 | ||||||||||||
Other (expense) income, net | (318 | ) | (1 | ) | (9 | ) | (328 | ) | ||||||||
Total other expense, net | (318 | ) | (1 | ) | (5,153 | ) | (5,472 | ) | ||||||||
Income from continuing operations before income taxes | 22,516 | (272 | ) | (7,686 | ) | 14,558 | ||||||||||
Income tax (benefit) expense | 839 | — | (18,022 | ) | (17,183 | ) | ||||||||||
Income from continuing operations | 21,677 | (272 | ) | 10,336 | 31,741 | |||||||||||
Loss from discontinued operations, net of tax | — | — | (20 | ) | (20 | ) | ||||||||||
Net income | $ | 21,677 | $ | (272 | ) | $ | 10,316 | $ | 31,721 | |||||||
Consolidated capital expenditures (1) | $ | 6,696 | $ | — | $ | — | $ | 6,696 | ||||||||
(1) Excludes assets acquired in the Sasol acquisition.
Nine Months Ended September 30, 2021 | ||||||||||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 142,696 | $ | — | $ | — | $ | 142,696 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Production expense | 57,478 | 261 | 21 | 57,760 | ||||||||||||
Exploration expense | 1,286 | — | — | 1,286 | ||||||||||||
Depreciation, depletion and amortization | 16,860 | — | 68 | 16,928 | ||||||||||||
General and administrative expense | 885 | 244 | 11,092 | 12,221 | ||||||||||||
Bad debt expense and other | 814 | — | — | 814 | ||||||||||||
Total operating costs and expenses | 77,323 | 505 | 11,181 | 89,009 | ||||||||||||
Other operating expense, net | (87 | ) | — | (353 | ) | (440 | ) | |||||||||
Operating income | 65,286 | (505 | ) | (11,534 | ) | 53,247 | ||||||||||
Other income (expense): | ||||||||||||||||
Derivative instruments loss, net | — | — | (21,070 | ) | (21,070 | ) | ||||||||||
Interest (expense) income, net | — | — | 9 | 9 | ||||||||||||
Other (expense) income, net | 6,854 | (2 | ) | (2,764 | ) | 4,088 | ||||||||||
Total other expense, net | 6,854 | (2 | ) | (23,825 | ) | (16,973 | ) | |||||||||
Income from continuing operations before income taxes | 72,140 | (507 | ) | (35,359 | ) | 36,274 | ||||||||||
Income tax (benefit) expense | 10,318 | 1 | (21,591 | ) | (11,272 | ) | ||||||||||
Income from continuing operations | 61,822 | (508 | ) | (13,768 | ) | 47,546 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (72 | ) | (72 | ) | ||||||||||
Net income | $ | 61,822 | $ | (508 | ) | $ | (13,840 | ) | $ | 47,474 | ||||||
Consolidated capital expenditures (1) | $ | 10,993 | $ | — | $ | — | $ | 10,993 | ||||||||
(1) Excludes assets acquired in the Sasol acquisition.
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Long-lived assets from continuing operations: | ||||||||||||||||
As of September 30, 2022 | $ | 184,484 | $ | 10,000 | $ | 227 | $ | 194,711 | ||||||||
As of December 31, 2021 | $ | 84,156 | $ | 10,000 | $ | 168 | $ | 94,324 | ||||||||
(in thousands) | Gabon | Equatorial Guinea | Corporate and Other | Total | ||||||||||||
Total assets from continuing operations: | ||||||||||||||||
As of September 30, 2022 | $ | 313,746 | $ | 10,689 | $ | 70,338 | $ | 394,773 | ||||||||
As of December 31, 2021 | $ | 201,748 | $ | 10,548 | $ | 50,794 | $ | 263,090 | ||||||||
Information about the Company’s most significant customers
The Company currently sells crude oil production from Gabon under term contractscrude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. From February 2019 to January 2020, crude oil sales were to Mercuria Energy Trading SA (“Mercuria”). The Company signedwas previously party to a new contractCOSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that coverscovered sales from February 2020 through JanuaryJuly 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. This COSPA has been terminated.
As discussed further in Note 11, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an initial aggregate maximum principal amount available of up to $50.0 million. In connection with the entry into the Facility Agreement, the Company entered into a COSMA with Glencore pursuant to which the Company agreed to make Glencore the exclusive offtaker and marketer of all of the crude oil produced from the Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of the Facility (as defined in the Facility Agreement). Pursuant to the COSMA, Glencore agreed to buy and market the Company’s crude oil with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
During the three and nine months ended September 30, 2022 and 2021, revenues from sales of crude oil to Exxon were 100% of the Company’s total revenues from customers.customers for the period of January 2021 through July 2022 and revenues from sales of crude oil to Glencore were 100% of the Company’s total revenues from customers for the period of August through September 2022.
5.EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.
A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Net income (numerator): | ||||||||||||||||
Income from continuing operations | $ | 6,894 | $ | 31,741 | $ | 34,194 | $ | 47,546 | ||||||||
Income from continuing operations attributable to unvested shares | (75 | ) | (404 | ) | (457 | ) | (755 | ) | ||||||||
Numerator for basic | 6,819 | 31,337 | 33,737 | 46,791 | ||||||||||||
Reallocation of earnings to participating securities for considering dilutive securities | — | — | 3 | — | ||||||||||||
Numerator for dilutive | $ | 6,819 | $ | 31,337 | $ | 33,740 | $ | 46,791 | ||||||||
Loss from discontinued operations, net of tax | $ | (26 | ) | $ | (20 | ) | $ | (58 | ) | $ | (72 | ) | ||||
Income from discontinued operations attributable to unvested shares | — | — | 1 | 1 | ||||||||||||
Numerator for basic | (26 | ) | (20 | ) | (57 | ) | (71 | ) | ||||||||
Reallocation of earnings to participating securities for considering dilutive securities | — | — | — | — | ||||||||||||
Numerator for dilutive | $ | (26 | ) | $ | (20 | ) | $ | (57 | ) | $ | (71 | ) | ||||
Net Income | $ | 6,868 | $ | 31,721 | $ | 34,136 | $ | 47,474 | ||||||||
Net income attributable to unvested shares | (75 | ) | (404 | ) | (456 | ) | (754 | ) | ||||||||
Numerator for basic | 6,793 | 31,317 | 33,680 | 46,720 | ||||||||||||
Reallocation of earnings to participating securities for considering dilutive securities | — | — | 3 | — | ||||||||||||
Numerator for dilutive | $ | 6,793 | $ | 31,317 | $ | 33,683 | $ | 46,720 | ||||||||
Weighted average shares (denominator): | ||||||||||||||||
Basic weighted average shares outstanding | 59,068 | 58,586 | 58,900 | 58,102 | ||||||||||||
Effect of dilutive securities | 382 | 330 | 435 | 552 | ||||||||||||
Diluted weighted average shares outstanding | 59,450 | 58,916 | 59,335 | 58,654 | ||||||||||||
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive | 388 | 138 | 195 | 282 | ||||||||||||
6. REVENUE
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
(in thousands) | |||||||||||
Net income (loss) (numerator): | |||||||||||
Income (loss) from continuing operations | $ | 31,741 | $ | 7,607 | $ | 47,546 | $ | (44,545) | |||
Income from continuing operations attributable to unvested shares | (404) | (121) | (755) | — | |||||||
Numerator for basic | 31,337 | 7,486 | 46,791 | (44,545) | |||||||
(Income) loss from continuing operations attributable to unvested shares | — | — | — | — | |||||||
Numerator for dilutive | $ | 31,337 | $ | 7,486 | $ | 46,791 | $ | (44,545) | |||
Income (loss) from discontinued operations, net of tax | $ | (20) | $ | 11 | $ | (72) | $ | (41) | |||
(Income) loss from discontinued operations attributable to unvested shares | — | — | 1 | — | |||||||
Numerator for basic | (20) | 11 | (71) | (41) | |||||||
(Income) loss from discontinued operations attributable to unvested shares | — | — | — | — | |||||||
Numerator for dilutive | $ | (20) | $ | 11 | $ | (71) | $ | (41) | |||
Net income (loss) | $ | 31,721 | $ | 7,618 | $ | 47,474 | $ | (44,586) | |||
Net income attributable to unvested shares | (404) | (121) | (754) | — | |||||||
Numerator for basic | 31,317 | 7,497 | 46,720 | (44,586) | |||||||
Net (income) loss attributable to unvested shares | — | — | — | — | |||||||
Numerator for dilutive | $ | 31,317 | $ | 7,497 | $ | 46,720 | $ | (44,586) | |||
Weighted average shares (denominator): | |||||||||||
Basic weighted average shares outstanding | 58,586 | 57,456 | 58,102 | 57,628 | |||||||
Effect of dilutive securities | 330 | 285 | 552 | — | |||||||
Diluted weighted average shares outstanding | 58,916 | 57,741 | 58,654 | 57,628 | |||||||
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive | 138 | 1,801 | 282 | 3,465 | |||||||
6. REVENUE
Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs. The COSPAs have been and will be renewed or replaced from time to time either with the current buyerCOSMAs. COSPAs or another buyer. The current COSPA with Exxon is scheduled to expire on January 31, 2022. See Note 4 under “Information about the Company’s most significant customers” for further discussion.
COSPAsCOSMAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer going forward. Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA.COSPA or COSMAs. See Note 4 under “Information about the Company’s most significant customers”for further discussion.
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e., the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a)606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
The Company accounts for production imbalances as a reduction in reserves. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the existing proved reserves were not adequate to cover an imbalance.
For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.
In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame Marin block PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame Marin block PSC includeincludes provisions for payments to the government of Gabon forfor: royalties based on 13% of production at the published price, and a shared portion of “Profit Oil” determined based on daily production rates as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame Marin block PSC provides that the government of Gabon may settle these obligations in-kind, i.e., taking crude oil barrels, rather than with cash payments.
To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers. Should the government elect to take the production attributable to its royalty in-kind, the Company would no longer have sales to customers associated with production assigned to royalties.
With respect to the government’s share of Profit Oil, the Etame Marin block PSC provides that the corporate income tax liability ismay be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected asin the current provision for income tax expense. Prior to February 1,2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1,2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame Marin block PSC is reflected as revenue with an offsetting amount reported as a current income tax expense. Payments of the income tax expense will beare reported in the period that the government takes its Profit Oil in-kind, i.e., the period in which it lifts the crude oil. An in-kind payment of $20.1 million was made with the September 2021 lifting. With the September lifting, the government lifted more oil in-kind than what was owed to it in foreign taxes. Therefore, theThe Company has a $2.1$28.1 million foreign income tax receivablepayable as of September 30, 2021.2022. As of December 31, 2020,2021, the foreign taxes payable attributable to this obligation was $0.9$3.1 million.
Certain amounts associated with the carried interest in the Etame Marin block discussed above are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.
The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the Etame Marin block PSC.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Revenue from customer contracts: | ||||||||||||||||
Sales under the COSPA or COSMA | $ | 87,661 | $ | 42,056 | $ | 289,290 | $ | 136,693 | ||||||||
Other items reported in revenue not associated with customer contracts: | ||||||||||||||||
Gabonese government share of Profit Oil taken in-kind | — | 20,103 | — | 20,103 | ||||||||||||
Carried interest recoupment | 2,360 | 1,794 | 5,843 | 5,948 | ||||||||||||
Royalties | (11,924 | ) | (8,054 | ) | (37,395 | ) | (20,048 | ) | ||||||||
Crude oil and natural gas sales | $ | 78,097 | $ | 55,899 | $ | 257,738 | $ | 142,696 | ||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Revenue from customer contracts: | (in thousands) | ||||||||||
Sales under the COSPA | $ | 42,056 | $ | 13,797 | $ | 136,693 | $ | 53,057 | |||
Other items reported in revenue not associated with customer contracts: | |||||||||||
Gabonese government share of Profit Oil taken in-kind | 20,103 | 6,883 | 20,103 | 8,738 | |||||||
Carried interest recoupment | 1,794 | 280 | 5,948 | 1,273 | |||||||
Royalties | (8,054) | (2,704) | (20,048) | (8,449) | |||||||
Crude oil and natural gas sales | $ | 55,899 | $ | 18,256 | $ | 142,696 | $ | 54,619 | |||
7.CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
|
As of September 30, 2021 | As of December 31, 2020 | |||||
(in thousands) | ||||||
Crude oil and natural gas properties and equipment - successful efforts method: | ||||||
Wells, platforms and other production facilities | $ | 480,872 | $ | 441,879 | ||
Work-in-progress | 2,278 | 169 | ||||
Undeveloped acreage | 23,735 | 21,476 | ||||
Equipment and other | 18,694 | 9,276 | ||||
525,579 | 472,800 | |||||
Accumulated depreciation, depletion, amortization and impairment | (451,477) | (435,764) | ||||
Net crude oil and natural gas properties, equipment and other | $ | 74,102 | $ | 37,036 | ||
The Company’s crude oil and natural gas properties and equipment is comprised of the following:
| As of September 30, 2022 | As of December 31, 2021 | |||||||
(in thousands) | ||||||||
Crude oil and natural gas properties and equipment - successful efforts method: | ||||||||
Wells, platforms and other production facilities | $ | 556,973 | $ | 488,756 | ||||
Work-in-progress | 60,749 | 13,515 | ||||||
Undeveloped acreage | 23,735 | 23,735 | ||||||
Equipment and other | 28,641 | 23,478 | ||||||
| 670,098 | 549,484 | |||||||
Accumulated depreciation, depletion, amortization and impairment | (475,387 | ) | (455,160 | ) | ||||
Net crude oil and natural gas properties, equipment and other | $ | 194,711 | $ | 94,324 | ||||
Extension of Term of Etame Marin Block PSC
On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Consortium”“Etame Consortium”), received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a 63.575% participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.
The PSC Extension extended the term for each of the 3three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17,2018, the effective date of the PSC Extension. The PSC Extension, also grantedwith two five-year options to extend the Consortium the right for 2 additional extension periods of five years each. The PSC Extension further allows the Consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in the PSC Extension.PSC.
In consideration for the PSC Extension, the Consortium agreed to a signing bonus of $65.0 million ($21.8 million, net to VAALCO) payable to the government of Gabon (the “signing bonus”). The Consortium paid $35.0 million ($11.8 million, net to VAALCO) in cash on September 26, 2018 and paid $25.0 million ($8.4 million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Consortium as of the effective date. An additional $5.0 million ($1.7 million, net to VAALCO) was paid in cash in February 2020 by the Consortium following the end of the drilling activities described below.
As required under the PSC Extension, the Consortium completed drilling 2 development wells and 2 appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Consortium completed the 2 technical studies at a cost of $1.5 million gross ($0.5 million, net to VAALCO).
In accordance with the Etame Marin block PSC, the Etame Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Under the PSC Extension, the Cost Recovery Percentage increased to 80% for the tenten-year-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%. The government of Gabon will acquire from the Etame Consortium an additional 2.5% gross working interest carried by the Etame Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is 1.6%.
Proved Properties
The Company reviews the crude oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.
There was no triggering event in the three and nine months ended September 30, 2021 2022 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher future strip pricesforward price curves for the third quarter of 2021 compared to the second quarter of 2021,2022 and that the Company incurred no significantexpected capital expenditures in the period related to the Etame Marin block.
There was no triggering event in the third quarter of 2020 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher future strip prices for the third quarter of 2020 compared to the second quarter of 2020, and that the Company incurred no significant capital expenditures in the period related to the Etame Marin block. Declining forecasted oil prices in the first quarter of 2020 caused the Company to perform an impairment review during this period. The impairment test was performed using the year end 2019 independently prepared reserve report, estimated reserves for the South East Etame 4H well completed in March 2020 and forward price curves. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Etame Marin block were less than the book value for the block, resulting in the Company recording a $30.6 million impairment loss to write down the Company’s investment to its fair value of $15.6 million.
Undeveloped Leasehold Costs
VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved ourthe Company's appointment as operator for Block P on November 12, 2019. The Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million in the event that there is commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. On April 12, 2021, the majority of non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties. As a result, VAALCO’s working interest willwould increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of September 30, 2021,2022, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The Company has completedOn July 15, 2022 VAALCO, on behalf of itself and Guinea Ecuatorial de Petroleós (“GEPetrol”), submitted to the EG MMH a feasibility studyplan of a standalone production development opportunity offor the Venus discovery ondevelopment in Block P. VAALCO is now proceeding to a field development concept and will work closely with theThe other Block P joint venture ownersowner, Atlas Petroleum International Limited, did not participate in the submission. On September 26, 2022, the EG MMH approved the submitted plan of development. Final documents to complete this overeffect the coming months.plan of development are subject to EG MMH approval and are under negotiations among all parties. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.
As a result of the PSC Extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3$2.3 million of costs were transferred to proved leasehold costs leaving athe remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at September 30, 20212022 was $13.7 million.
Capitalized Equipment Inventory
Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating income (expense), net” line item of the condensed consolidated statements of operations but were not material for the three and nine months ended September 30, 2021 2022 and 2020.2021.
8. DERIVATIVES AND FAIR VALUE
The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the Company’s exposure to price fluctuations.
Commodity swaps – On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average price of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. On January 22, 2021, the Company entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for a quantity of 709,262 barrels. On May 6, 2021, the Company
entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. See the table below for the unexpired barrels aslist of September 30, 2021.outstanding contracts.
Settlement Period | Type of Contract | Index | Barrels | Weighted Average Price | ||||||||
October 2021 to January 2022 | Swaps | Dated Brent | 236,421 | $ | 53.10 | |||||||
October 2021 | Swaps | Dated Brent | 108,882 | $ | 66.00 | |||||||
November 2021 to February 2022 | Swaps | Dated Brent | 314,420 | $ | 67.70 | |||||||
March 2022 to June 2022 | Swaps | Dated Brent | 460,000 | $ | 72.00 | |||||||
1,119,723 | ||||||||||||
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||||||||
(Bbls) | (per Bbl) | (per Bbl) | ||||||||||||||
October 2022 to December 2022 | Collars | Dated Brent | 109,000 | $ | 70.00 | $ | 122.00 | |||||||||
While these commodity swapsderivative instruments are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes. In connection with the RBL facility entered in May 2022, the Company is required to hedge a portion of its anticipated oil production at the time the Company draws down on the borrowing base.
The crude oil swap contractsderivative instruments are measured at fair value using the Income Method. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the swapderivative instrument contracts’ fair value includes the impact of the counterparty’s non-performance risk.
To mitigate counterparty risk, the Company enters into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
At times, the Company’s counterparties require that it post collateral for changes in the net fair value of the derivative contracts. This cash collateral is reported in the line item "Restricted cash" on the condensed consolidated balance sheets.
The following table sets forth the gain (loss)loss on derivative instruments on the Company’s condensed consolidated statements of operations:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
Derivative Item | Statement of Operations Line | 2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||||
Commodity derivatives | Cash settlements paid on matured derivative contracts, net | $ | (9,124 | ) | $ | (4,186 | ) | $ | (42,683 | ) | $ | (10,189 | ) | |||||
Unrealized gain (loss) | 12,902 | (961 | ) | 5,161 | (10,881 | ) | ||||||||||||
Derivative instruments gain (loss), net | $ | 3,778 | $ | (5,147 | ) | $ | (37,522 | ) | $ | (21,070 | ) | |||||||
Subsequent Event
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
Derivative Item | Statement of Operations Line | 2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands) | ||||||||||||||
Crude oil swaps | Realized gain (loss) - contract settlements | $ | (4,186) | $ | — | $ | (10,189) | $ | 7,216 | |||||
Unrealized loss | (961) | — | (10,881) | (633) | ||||||||||
Derivative instruments gain (loss), net | $ | (5,147) | $ | — | $ | (21,070) | $ | 6,583 | ||||||
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||
January 2023 to March 2023 | Collars | Dated Brent | 101,000 | $ 65.00 | $ 120.00 |
9. ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other balances were comprised of the following:
As of September 30, 2022 | As of December 31, 2021 | |||||||
(in thousands) | ||||||||
Accrued accounts payable invoices | $ | 21,703 | $ | 11,967 | ||||
FPSO demobilization | 8,867 | — | ||||||
Gabon DMO, PID and PIH obligations | 10,803 | 9,465 | ||||||
Derivative liability - crude oil swaps | — | 4,806 | ||||||
Capital expenditures | 26,516 | 11,327 | ||||||
Stock appreciation rights – current portion | 544 | 609 | ||||||
Accrued wages and other compensation | 2,676 | 2,124 | ||||||
ARO Obligation | 6,701 | 6,745 | ||||||
Other | 5,338 | 2,401 | ||||||
Total accrued liabilities and other | $ | 83,148 | $ | 49,444 | ||||
As of September 30, 2021 | As of December 31, 2020 | |||||
(in thousands) | ||||||
Accrued accounts payable invoices | $ | 12,447 | $ | 4,070 | ||
Gabon DMO, PID and PIH obligations | 8,531 | 3,960 | ||||
Derivative liability - crude oil swaps | 10,881 | — | ||||
Capital expenditures | 2,475 | 435 | ||||
Stock appreciation rights – current portion | 761 | 2,289 | ||||
Accrued wages and other compensation | 2,411 | 2,108 | ||||
Other | 2,351 | 4,322 | ||||
Total accrued liabilities and other | $ | 39,857 | $ | 17,184 | ||
10.COMMITMENTS AND CONTINGENCIES
Abandonment funding
Under the terms of the Etame Marin block PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028.2028, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-
refundable. Thenon-refundable. In November 2021, an abandonment study was done and the estimate used for this purpose is approximately $61.8$81.3 million ($36.447.9 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. Through September 30, 2021, $37.92022, $32.0 million ($22.318.8 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the condensed consolidated balance sheet.sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
On March 5,2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of an international commercial bank holding the abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for CEMAC, of which Gabon is one of the six member states. The U.S. dollars were converted to local currency with a credit back to the Gabonese branch. During the three and nine months ended September 30, 2021, 2022, the Company recorded a $1.3 million and $3.0 million foreign currency loss, associated with the abandonment funding account was $0.6 million. During the nine months ended September 30, 2021, the Company recorded $1.1 million in foreign currency lossesrespectively, associated with the abandonment funding account. During the three and nine months ended September 30, 2021, the Company recorded a $0.6 million and a $1.1 million foreign currency loss, respectively, associated with the abandonment funding account. In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for opening of U.S. dollars escrow accounts for the abandonment funds at BEAC. The Company is currently working with the extractive industry to formulate the agreements which are expected to be finalized in 2022, that regulate these accounts. Accordingly, pursuant to Amendment No.5 to of the Etame Marin block PSC provides that required these funds to be in U.S. dollars, once the event thataccount for the Gabonese bank fails for any reason to reimburse allU.S. dollars abandonment fund is open at BEAC the Company will resume its funding of the principal and interest due,abandonment fund in compliance with the Company and the other joint venture owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.Etame PSC.
FPSO charter
In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for 2 two one-yearone-year periods beyond September 2020. These elections have beenwere made, and the charter has beenwas extended through September 2022.On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 and ratified certain decommissioning and demobilization items associated with exiting the contract.
Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022, and other demobilization fees totaling $15.3 million on a gross basis, $8.9 million net to VAALCO Gabon. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. payments under the charter.
The Company’s net share of theFPSO charter payment is 58.8%, or approximately $19.4 millionincludes a $0.93 per year. Although the Company believes the needbarrel charter fee for performance under theproduction up to 20,000 barrels of crude oil per day and a $2.50 per barrel charter guarantee is remote, the Company recorded a liabilityfee for those barrels produced in excess of $0.1 million as20,000 barrels of September 30, 2021 and $0.4 million ascrude oil per day.
Regulatory and Joint Interest Audits and Related Matters
The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the Company’s petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the Company’s joint operating agreements.
In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years 2013 through 2014. The Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the newly appointed representatives to resolve the audit findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.
Between 2019 and 2021, the government of Gabon conducted an audit of the operations in Gabon, covering the years 2015 and 2016. The Company has not yet received the findings from this audit.
In 2019, the Etame joint venture owners conducted audits for the years 2017 and 2018. In June 2020, the Company agreed to a $0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners, Addax Petroleum Gabon S.A. There are now no unresolved matters related to the joint venture owner audits for these years.
FSO
FSO
On August 31, 2021, VAALCOthe Company and its co-venturers at Etame approved the Bareboat Contract (the “Bareboat Contract”) and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. to replace the existing FPSO with a Floating Storage and Offloading unit (“FSO”). The FSO Agreements requirerequired a prepayment of $2 million gross, ($1.3$1.3 million net)net to the Company, in 2021 and $5 million gross, ($3.2$3.2 million net)net to the Company, in 2022 of which $6 million will be recovered against future rentals. Current total fieldblock level capitalfield conversion estimates are $40$70 to $50$86 million gross, ($26$45 to $32$55 million net to VAALCO) with about $5 million net expected in 2021 and the remainder in 2022. No other prepayments are required under theCompany. The FSO Agreements until the vessel is accepted by the Company at the Etame Marin Block location. The Bareboat Contract containscontain purchase provisions and termination provisions. The Company does not expect to utilizecurrently believes that all of the terminations provision underassociated engineering, long-lead equipment and significant contracts are proceeding in-line with the FSO Agreements.
Dividend Policy
anticipated timelines and expected delivery schedules for the deployment of the FSO. On August 2, 2021,October 19, 2022, the vessel is on location at the Etame Marin block and the Company has issued its final acceptance certificate of the FSO.
Dividend Policy
On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy beginning in of an expected $0.0325 per common share per quarter. On March 18, 2022, the first quarterCompany paid a quarterly cash dividend of 2022. Additional details$0.0325 per share of common stock to the stockholders of record at the close of business on February 18, 2022. On June 24, 2022, the Company paid a quarterly cash dividend of $0.0325 per share of common stock to the stockholders of record at the close of business on May 25, 2022. On September 23, 2022, the Company paid a quarterly cash dividend of $0.0325 per share of common stock to the stockholders of record at the close of business on August 25, 2022.
Payment of future dividends, if any, will be at the discretion of the initial record dateboard of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and payable date will be announced in early 2022.current and anticipated cash needs.
Other contractual commitments
In August 2020, the Company entered into an agreement to acquire approximately 1,000 square kilometers of 3-D seismic data in the Company’s Etame Marin block. The acquisition was completed in the fourth quarter of 2020 and the processing of the seismic data began in January 2021. The cost, net to VAALCO, is estimated to be approximately $2.2 million or $3.4 million gross.
In June 2021, the Company entered into a short-term agreement with an affiliate of Borr Drilling Limited to drill a minimum of 3three wells with options to drill additional wells. Upon completion of the ETBSM 1HB-ST2 well, the commitment to Borr Drilling Limited was satisfied. The drillingCompany has exercised its options to extend its contract for the existing rig is expectedand expects to be delivered after December 1, 2021 and before January 1, release the rig in November 2022.
11. LEASES
Subsequent Event
On October 31, 2022, the Company announced a quarterly cash dividend of $0.0325 per share of common stock for the fourth quarter of 2022 which is payable December 22, 2022to stockholders of record at the close of business on November 22, 2022.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
On November 1, 2022, the Company announced that the Company’s newly-expanded board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with the Company’s business combination with TransGlobe. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “Plan”) to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.
The actual timing, number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, the Company's stock price, general business and market conditions, and alternative investment opportunities. Under ASC 842, the Plan, the Company’s third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the Plan.
11. DEBT
As of September 30, 2022 and December 31, 2021, the Company had no outstanding debt.
On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.
The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is determined and redetermined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.
Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).
Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.
The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of September 30, 2022, the Company's borrowing base was $50.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. At September 30, 2022, the Company was in compliance with all debt covenants and had no outstanding borrowings under the facility.
The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).
Deferred financing costs incurred in connection with securing the Facility were $1.4 million, $1.5 million net of amortization of $0.1 million, which is carried in the accompanying condensed consolidated balance sheets in the line item "Other long-term assets" and is amortized on a straight-line basis, which approximates the effective interest method, over the term of the Facility and included in interest expense in the accompanying condensed consolidated statements of operations.
Subsequent Event
In connection with the Arrangement with TransGlobe in October 2022, and prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately LeasesCAD$4.1, million.
12. LEASES
Under the leasing standard that became effective January 1,2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a Right-of-Use (“ROU”)ROU asset and a lease liability at the present value of the future lease payments.
Practical Expedients –The
The Company elected to use theseall the practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1,2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption. The adoption of ASC 842 resulted in a material increase in the Company’s total assets and liabilities on the Company’s condensed consolidated balance sheet as certain of its operating
Operating leases are significant. In addition, adoption resulted in a decrease in working capital as the ROU asset is noncurrent, but the lease liability has both long-term and short-term portions. There was no material overall impact on results of operations or cash flows. In the statement of cash flows, operating leases remain an operating activity.
The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and helicopters, warehouse and storage facilities, equipment and the FPSO. The duration for these agreements rangeranges from 129 to 2630 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for the FPSO, the marine vessels, helicopter,and certain equipment and warehouse and storage facilities used in the joint operations includes the gross amount of the lease components.
For all other leases that contain an option to extend, the Company has concluded that it is not reasonably certain it will exercise the renewal option and the renewal periods have been excluded in the calculation for the ROU assets and liabilities.
During the third quarter of 2019, the Company notified the lessor of the FPSO of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021. Similarly, during the third quarter of 2020, the Company gave notification to extend the FPSO lease to September 2022.
The
On September 9, 2022, the Company entered into an addendum to the FPSO helicopter,contract which extends the contract from September 2022 through October 4, 2022 and sets forth both the Company’s and lessor's rights and obligations with respect to demobilization and decommissioning. Under ASC 842, the Company was required to reassess the lease for lease classification at the time the Company entered into the amendment. Accordingly, the Company assessed the lease as a short-term lease.
The marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the initial calculation of ROU assets and lease liabilities.
Financing leases
The Company is currently a party to several financing lease agreements for the FSO and generators used in the operations of the Etame Marin block. On February 15, 2022, the Company signed a contract for a finance lease of generators and related parts. The related ROU asset and lease liability was recorded on the lease commencement date of February 15, 2022. The remaining minimum duration for this lease is 59 months as of September 30, 2022.
In August 2021, the Company signed the FSO agreements to lease a FSO to replace the current FPSO whose term will endended in SeptemberOctober 2022. Under the terms of the Bareboat Contract,FSO agreements, a third party is expected to improvemodify the leased vessel in order to comply withmeet the Company’s crude-oil production requirements. The vessel is expected to arrivearrived on location in the Etame Marin Blockblock in SeptemberAugust 2022. On October 19, 2022,the Company signed the final acceptance certificate at which time control of the vessel will transfertransferred to the Company.
All leases
For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it will extend the lease beyond the initial lease term. When the Company believes it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. TheThe Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.
For the three and nine months ended September 30, 2021 2022 and 2020,2021, the components of the lease costs and the supplemental information were as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Lease cost: | ||||||||||||||||
Finance lease cost (1) | $ | 97 | $ | — | $ | 261 | $ | — | ||||||||
Operating lease cost | 2,547 | 4,386 | 11,008 | 13,266 | ||||||||||||
Short-term lease cost (2) | 3,115 | 585 | 4,328 | 1,828 | ||||||||||||
Variable lease cost (3) | 1,264 | 1,584 | 4,511 | 4,645 | ||||||||||||
Total lease expense | 7,023 | 6,555 | 20,108 | 19,739 | ||||||||||||
Lease costs capitalized | 1,877 | — | 3,300 | — | ||||||||||||
Total lease costs | $ | 8,900 | $ | 6,555 | $ | 23,408 | $ | 19,739 | ||||||||
2022 | 2021 | |||||||
Other information: | ||||||||
Cash paid for amounts included in the measurement of lease liabilities: | ||||||||
Operating cash flows attributable to finance leases | $ | 26 | $ | — | ||||
Weighted-average remaining lease term (in years) | 4.92 | — | ||||||
Weighted-average discount rate | 3.54 | % | — | |||||
Operating cash flows attributable to operating leases | $ | 19,243 | $ | 18,018 | ||||
Weighted-average remaining lease term (in years) | 1.51 | 1.0 | ||||||
Weighted-average discount rate | 5.12 | % | 6.09 | % | ||||
(1) | Represents depreciation and interest associated with financing leases. |
(2) | Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded. |
(3) | Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Lease cost: | (in thousands) | |||||||||||
Operating lease cost | $ | 4,386 | $ | 4,519 | $ | 13,266 | $ | 13,044 | ||||
Short-term lease cost | 585 | 457 | 1,828 | 908 | ||||||||
Variable lease cost | 1,584 | 1,715 | 4,645 | 5,779 | ||||||||
Total lease expense | 6,555 | 6,691 | 19,739 | 19,731 | ||||||||
Lease costs capitalized | — | 11 | — | 3,470 | ||||||||
Total lease costs | $ | 6,555 | $ | 6,702 | $ | 19,739 | $ | 23,201 | ||||
Other information: | ||||||||||||
Cash paid for amounts included in the measurement of lease liabilities: | 2021 | 2020 | ||||||||||
Operating cash flows attributable to operating leases | $ | 18,018 | $ | 20,564 | ||||||||
Weighted-average remaining lease term | 1.0 years | 2.0 years | ||||||||||
Weighted-average discount rate | 6.09% | 6.09% | ||||||||||
The table below describes the presentation of the total lease cost on the Company’s condensed consolidated statement of operations. As discussed above, the Company’s joint venture owners are required to reimburse the Company for their share of certain expenses, including certain lease costs.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Finance lease cost | $ | 165 | $ | — | $ | 261 | $ | — | ||||||||
Production expense | 4,049 | 3,827 | 11,607 | 10,328 | ||||||||||||
General and administrative expense | 48 | 49 | 111 | 145 | ||||||||||||
Lease costs billed to the joint venture owners | 3,441 | 2,679 | 9,327 | 9,266 | ||||||||||||
Total lease expense | 7,703 | 6,555 | 21,306 | 19,739 | ||||||||||||
Lease costs capitalized | 1,197 | — | 2,102 | — | ||||||||||||
Total lease costs | $ | 8,900 | $ | 6,555 | $ | 23,408 | $ | 19,739 | ||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands) | ||||||||||||
Production expense | $ | 3,827 | $ | 2,063 | $ | 10,328 | $ | 6,082 | ||||
General and administrative expense | 49 | 49 | 145 | 147 | ||||||||
Lease costs billed to the joint venture owners | 2,679 | 4,586 | 9,266 | 15,807 | ||||||||
Total lease expense | 6,555 | 6,698 | 19,739 | 22,036 | ||||||||
Lease costs capitalized | — | 4 | — | 1,165 | ||||||||
Total lease costs | $ | 6,555 | $ | 6,702 | $ | 19,739 | $ | 23,201 | ||||
The following table describes the future maturities of the Company’s operating lease liabilities at September 30, 2021:2022:
Operating Leases | Finance Leases | ||||||||||||||||
Lease Obligation | (in thousands) | ||||||||||||||||
Year | (in thousands) | ||||||||||||||||
2021 | $ | 3,489 | |||||||||||||||
2022 | 9,685 | $ | 185 | $ | 92 | ||||||||||||
2023 | 179 | 1,339 | 368 | ||||||||||||||
2024 | 197 | 368 | |||||||||||||||
2025 | 33 | 368 | |||||||||||||||
Thereafter | — | 537 | |||||||||||||||
13,353 | 1,754 | 1,733 | |||||||||||||||
Less: imputed interest | 370 | 33 | 165 | ||||||||||||||
Total lease liabilities | $ | 12,983 | $ | 1,721 | $ | 1,568 | |||||||||||
Under the joint operating agreements, other joint venture owners are obligated to fund $5.5$1.4 million of the $13.4$3.5 million in future lease liabilities.
12.13. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations:
(in thousands) | As of September 30, 2021 | As of December 31, 2020 | ||||
Beginning balance | $ | 17,334 | $ | 15,844 | ||
Accretion | 1,179 | 893 | ||||
Additions | 14,564 | 359 | ||||
Revisions | — | 238 | ||||
Ending balance | $ | 33,077 | $ | 17,334 | ||
(in thousands) | As of September 30, 2022 | As of December 31, 2021 | ||||||
Beginning balance | $ | 40,694 | $ | 17,334 | ||||
Accretion | 1,434 | 1,627 | ||||||
Additions | — | 14,564 | ||||||
Revisions | — | 7,169 | ||||||
Settlements | (180 | ) | — | |||||
Ending balance | $ | 41,948 | $ | 40,694 | ||||
Accretion is recorded in the line item “Depreciation, depletion and amortization” on the Company’s condensed consolidated statements of operations.
The Company is required under the Etame PSC for the Etame Marin block PSCin Gabon to conduct regular abandonment studies to update the estimated costs to abandonamounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completedprepared in November 2018. In 2020,2021. At December 31, 2021, associated with the study, the Company recorded $0.4an upward revision of $7.2 million to the asset retirement obligation primarily as a result of increased costs expected with the abandonment of the Etame Marin block and a change in additionsthe expected timing of the abandonment costs associated with the South East Etame 4H development well and $0.2 million in revisions associated with a U.S. property.termination of the FPSO charter. In connection with the Sasol Acquisition, as discussed in Note 3, the Company added $14.6 million of asset retirement obligations as a result of it increasing its interest in the Etame Marin block.block in 2021. As a result of the expected timing of the abandonment of the FPSO, included in the line item "Accrued liabilities and other" in the condensed consolidated balance sheet is $6.7 million of costs associated with the retirement obligation as of September 30, 2022.
13. SHAREHOLDERS’
14. SHAREHOLDERS’ EQUITY
Subsequent Event
On October 13, 2022, in connection with the closing of the Arrangement, (i) the total number of authorized shares of common stock of the Company was increased from 100 million to 160 million and (ii) VAALCO issued approximately 49.3 million shares to TransGlobe's shareholders.
Preferred stock –
Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. NaNNo shares of preferred stock were issued and outstanding as of September 30, 2021 2022 or December 31, 2020.2021.
Treasury stock – On June 20, 2019, the Board of Directors authorized and approved a share repurchase program for up to $10.0 million of the currently outstanding shares of the Company’s common stock over a period of 12 months. Under the stock repurchase program, the Company could repurchase shares through open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”).The Board of Directors also authorized the Company to enter into written trading plans under Rule 10b5-1 of the Exchange Act.
From commencement of the plan in June 2019 through April 13, 2020, the Company purchased 2,740,643 shares of common stock at an average price of $1.70 per share for an aggregate purchase price of $4.7 million under the plan. On April 13, 2020, the Board of Directors approved the termination of the share repurchase program; consequently, 0 further shares can be repurchased pursuant to the plan.
For the majority of restricted stock awards granted by the Company, the number of shares issued to the participant on the vesting date are net of shares withheld to meet applicable tax withholding requirements. In addition, when options are exercised, the participant may elect to remit shares to the Company to cover the tax liability and the cost of the exercised options. When this happens, the Company adds these shares to treasury stock and pays the taxes on the participant’s behalf.
Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in our financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 1415 for further discussion.
14.
15.STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS
The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Boardboard of Directorsdirectors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“(“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020“2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At September 30, 2021, 7,558,9752022, 6,645,319 shares were available for future grants under the 2020 Plan.
For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-oneone-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the nine months ended September 30, 2022, the Company settled in cash $0.8 million for stock appreciation rights and received $0.3 million for stock option exercises. During the nine months ended September 30, 2021, the Company settled in cash $3.1 million for stock appreciation rights and received $1.3 million for stock option exercises. During
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
Stock-based compensation - equity awards | $ | 541 | $ | 327 | $ | 1,560 | $ | 767 | ||||||||
Stock-based compensation - liability awards | (505 | ) | (302 | ) | 740 | 1,331 | ||||||||||
Total stock-based compensation | $ | 36 | $ | 25 | $ | 2,300 | $ | 2,098 | ||||||||
Subsequent Event
In connection with the nine months ended September 30, 2020,Arrangement with TransGlobe and pursuant to the Company did 0t settle any stock-basedArrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, will continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that will remain outstanding following the effective time of the Arrangement as described in the immediately preceding sentence, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021; and 64.4% for PSUs granted in 2022.
compensation. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
(in thousands) | ||||||||||||
Stock-based compensation - equity awards | $ | 327 | $ | 322 | $ | 767 | $ | 527 | ||||
Stock-based compensation - liability awards | (302) | (570) | 1,331 | (2,624) | ||||||||
Total stock-based compensation | $ | 25 | $ | (248) | $ | 2,098 | $ | (2,097) | ||||
Stock options and performance shares
Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Boardboard of Directorsdirectors that is generally a three-yearthree-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.
In March 2021, 2022, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 401,759241,358 shares at an exercise price of $3.14$6.41 per share and a life of ten years. For each performance stock option award, oneone-third-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day30-day average, exceeds $3.61$7.37 per share; performance stock options with respect to oneone-third-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day30-day average, exceeds $4.15$8.48 per share; and performance stock options with respect to the remaining oneone-third-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day30-day average, exceeds $4.78$9.75 per share. These awards are option awards that contain a market condition. Compensation cost for such awards is recognized ratably over the derived service period and compensation cost related to awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.
The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option. During the three and nine months ended September 30, 2021, 0 performance stock option awards issued under the 2020 Plan were exercised.
For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.
Because the Company has not historically paid cash dividends, no expected dividend yield was input to the Black-Scholes or Monte Carlo models.
During the nine months ended September 30, 2021 2022 and 2020,2021, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo model in 2021 and Black-Scholes models.Carlo.
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
2021 | 2020 | 2022 | 2021 | |||||||||||
Weighted average exercise price - ($/share) | $ | 3.14 | $ | 1.23 | $ | 6.41 | $ | 3.14 | ||||||
Expected life in years | 6.0 | 6.0 | 6.0 | 6.0 | ||||||||||
Average expected volatility | 75 | % | 74 | % | 72 | % | 75 | % | ||||||
Risk-free interest rate | 0.95 | % | 0.42 | % | 1.98 | % | 0.95 | % | ||||||
Expected dividend yield | 2.30 | % | — | |||||||||||
Weighted average grant date fair value - ($/share) | $ | 2.07 | $ | 0.79 | $ | 2.84 | $ | 2.07 | ||||||
Stock option activity associated with the Monte Carlo model for the nine months ended September 30, 20212022 is provided below:
Number of Shares Underlying Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||||||
(in thousands) | (in years) | |||||||||||||||
Outstanding at January 1, 2022 | 359 | $ | 1.96 | |||||||||||||
Granted | 241 | 6.41 | ||||||||||||||
Exercised | — | — | ||||||||||||||
Unvested shares forfeited | — | — | ||||||||||||||
Vested shares expired | — | — | ||||||||||||||
Outstanding at September 30, 2022 | 600 | $ | 3.75 | 8.59 | $ | 861 | ||||||||||
Exercisable at September 30, 2022 | 194 | $ | 1.68 | 7.90 | $ | 518 | ||||||||||
Number of Shares Underlying Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||
(in thousands) | (in years) | (in thousands) | |||||||||
Outstanding at January 1, 2021 | 644 | $ | 1.23 | ||||||||
Granted | 402 | 3.14 | |||||||||
Exercised | — | — | |||||||||
Unvested shares forfeited | (687) | 1.96 | |||||||||
Vested shares expired | — | — | |||||||||
Outstanding at September 30, 2021 | 359 | $ | 1.96 | 9.00 | $ | 378 | |||||
Exercisable at September 30, 2021 | 74 | $ | 1.23 | 8.74 | $ | 126 | |||||
Stock option activity associated with the Black-Scholes model for the nine months ended September 30, 20212022 is provided below:
Number of Shares Underlying Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||||||
(in thousands) | (in years) | |||||||||||||||
Outstanding at January 1, 2022 | 615 | $ | 1.58 | |||||||||||||
Granted | — | — | ||||||||||||||
Exercised | (229 | ) | 1.12 | |||||||||||||
Unvested shares forfeited | — | — | ||||||||||||||
Vested shares expired | — | — | ||||||||||||||
Outstanding at September 30, 2022 | 386 | $ | 1.86 | 1.21 | $ | 968 | ||||||||||
Exercisable at September 30, 2022 | 386 | $ | 1.86 | 1.21 | $ | 968 | ||||||||||
Number of Shares Underlying Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||
(in thousands) | (in years) | (in thousands) | |||||||||
Outstanding at January 1, 2021 | 1,804 | $ | 1.38 | ||||||||
Granted | — | — | |||||||||
Exercised | (1,088) | 1.20 | |||||||||
Unvested shares forfeited | (64) | 2.33 | |||||||||
Vested shares expired | — | — | |||||||||
Outstanding at September 30, 2021 | 652 | $ | 1.60 | 1.73 | $ | 876 | |||||
Exercisable at September 30, 2021 | 555 | $ | 1.47 | 1.61 | $ | 816 | |||||
During the nine months ended September 30, 2021, 504,8132022, 49,063 shares were added to treasury as a result of tax withholding on options exercised. During the nine months ended September 30, 2020, 0 shares were added to treasury as a result of tax withholding on options exercised.
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a threethree-year-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) (50) weeks following the date of grant). In March 2021, 2022, the Company issued 526,147353,424 shares of service- basedservice-based restricted stock to employees, with a grant date fair value of $3.14$6.41 per share. In addition, in June 2021, 2022, the Company issued 78,43230,687 shares of service-based restricted stock to directors, with a grant date fair value of $3.06$8.31 per share. The vesting of thesethe foregoing shares is dependent upon, among other things, the employees’ and directors’ continued service with the Company.
The following is a summary of activity for the nine months ended September 30, 2021:2022:
Restricted Stock | Weighted Average Grant Date Fair Value | ||||||||||||
Restricted Stock | Weighted Average Grant Date Fair Value | (in thousands) | |||||||||||
(in thousands) | |||||||||||||
Non-vested shares outstanding at January 1, 2021 | 1,155 | $ | 1.30 | ||||||||||
Non-vested shares outstanding at January 1, 2022 | 741 | $ | 2.36 | ||||||||||
Awards granted | 605 | 3.13 | 384 | 6.56 | |||||||||
Awards vested | (543) | 1.28 | (334 | ) | 2.25 | ||||||||
Awards forfeited | (462) | 2.00 | (32 | ) | 3.69 | ||||||||
Non-vested shares outstanding at September 30, 2021 | 755 | $ | 2.36 | ||||||||||
Non-vested shares outstanding at September 30, 2022 | 759 | $ | 4.48 | ||||||||||
During the nine months ended September 30, 2021, 68,1342022, 69,135 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the nine months ended September 30, 2020, 40,432 shares were added to treasury as a result
Stock appreciation rights (“SARs”(“SARs”)
SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Boardboard of Directors.directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Boardboard of Directors.directors.
During the nine months ended September 30, 2021 and 2020,2022, the Company did 0tnot grant SARs to employees or directors.
SAR activity for the nine months ended September 30, 20212022 is provided below:
Number of Shares Underlying SARs | Weighted Average Exercise Price Per Share | Weight Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||||||
(in thousands) | (in years) | (in thousands) | ||||||||||||||
Outstanding at January 1, 2022 | 362 | $ | 1.81 | |||||||||||||
Granted | — | — | ||||||||||||||
Exercised | (153 | ) | 1.71 | |||||||||||||
Unvested SARs forfeited | — | — | ||||||||||||||
Vested SARs expired | — | — | ||||||||||||||
Outstanding at September 30, 2022 | 209 | $ | 1.88 | 1.11 | $ | 517 | ||||||||||
Exercisable at September 30, 2022 | 209 | $ | 1.88 | 1.11 | $ | 517 | ||||||||||
Number of Shares Underlying SARs | Weighted Average Exercise Price Per Share | Term | Aggregate Intrinsic Value | ||||||||
(in thousands) | (in years) | (in thousands) | |||||||||
Outstanding at January 1, 2021 | 2,940 | $ | 1.33 | ||||||||
Granted | 0 | — | |||||||||
Exercised | (2,306) | 1.16 | |||||||||
Unvested SARs forfeited | (125) | 2.33 | |||||||||
Vested SARs expired | — | — | |||||||||
Outstanding at September 30, 2021 | 509 | $ | 1.83 | 2.23 | $ | 567 | |||||
Exercisable at September 30, 2021 | 338 | $ | 1.69 | 2.10 | $ | 423 | |||||
Other Benefit Plans
The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive 100% and 50%, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75% of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.
15.16. INCOME TAXES
The
VAALCO and its domestic subsidiaries file a consolidated U.S. income tax provision for VAALCO consists primarily of Gabonese and United States income taxes. The Company’s operations in otherreturn. Certain foreign jurisdictions have a 0% effective tax rate because the Company has incurred losses in those countries and has full valuation allowances against the corresponding net deferred tax assets. The Company files incomesubsidiaries also file tax returns in all jurisdictions where such requirements exist, withtheir respective local jurisdictions.
Income taxes attributable to continuing operations for the three and nine months ended September 30, 2022 and 2021 are attributable to foreign taxes payable in Gabon and the United States being its primary tax jurisdictions.
For interim reporting periods, the Company determines its tax expense by estimating an annual effectiveas well as income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and applies this tax rate to the Company’s ordinary income or loss to calculate its estimated tax expense or benefit. The tax effect of discrete items is recognizedtaxes in the period in which they occur at the applicable statutory tax rate.U.S.
Provision for income tax expense (benefit)taxes related to income from continuing operations consists of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
(in thousands) | ||||||||||||||||
U.S. Federal: | ||||||||||||||||
Current | $ | — | $ | — | $ | — | $ | — | ||||||||
Deferred | 461 | (17,619 | ) | (9,408 | ) | (19,668 | ) | |||||||||
Foreign: | ||||||||||||||||
Current | (1,165 | ) | 5,516 | 24,928 | 15,099 | |||||||||||
Deferred | 23,547 | (5,080 | ) | 48,947 | (6,703 | ) | ||||||||||
Total | $ | 22,843 | $ | (17,183 | ) | $ | 64,467 | $ | (11,272 | ) | ||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
U.S. Federal: | (in thousands) | |||||||||||
Current | $ | — | $ | 147 | $ | — | $ | (378) | ||||
Deferred | (17,619) | (442) | (19,668) | 9,546 | ||||||||
Foreign: | ||||||||||||
Current | 5,516 | 2,393 | 15,099 | 1,876 | ||||||||
Deferred | (5,080) | (4,857) | (6,703) | 17,426 | ||||||||
Total | $ | (17,183) | $ | (2,759) | $ | (11,272) | $ | 28,470 | ||||
The Company’s effective tax rate for the nine months ended September 30, 2021 2022 and 2020,2021, excluding the impact of discrete items, was 37.5%90.3% and (53%)37.5%, respectively. For the nine months ended September 30, 2021,2022, the Company’s overall effective tax rate was appreciably impacted by non-deductible items associated with operations (which includes losses on derivative instruments), transaction costs attributable to the impactTransGlobe Arrangement, and the release of deducting foreign taxes rather than crediting them, and a change in valuation allowance. Priorallowance attributable to the current period. The total tax expense for the nine months ended September 30, 2021,2022 includes a discrete adjustment for the release of an additional $20.2 million of valuation allowance was necessary due to the decline in crude oil prices caused by declining global economic activity and excess oil supply, which impacted the Company’s expected ability to utilize its deferred tax assets. However, the Company’s observationas a result of the increasing crude oil prices over a sustained period of time, lack of disruption in operations due to the pandemic, steadyan increase in global economic activity and oil supply demand over multiple quarters has removed much offorecasted future earnings. For the uncertainty and instability in the industry. The Company’s forecasts show these factors as having a positive impact on future taxable income. On the basis of these factors, the Company determined it was more likely than not that it will realize a portion of our deferred tax assets. Accordingly, the Company reversed $22.3 million of the valuation allowance based on estimated future earnings, which was treated as a discrete item for the three and nine months ended September 30, 2021. Should these factors continue to strengthen, further recognition of additional deferred tax assets may be warranted. The total change in valuation allowances for the nine months ended September 30, 2021 was $(15.8) million. For the three months ended September 30, 2021, 2022, the current tax expensebenefit of $5.5$1.2 million includes a $0.2an $8.7 million unfavorablefavorable oil price adjustment as a result of the change in value of the government’sgovernment of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $5.3an expense of $7.5 million for the period. For the nine months ended September 30, 2021, 2022, the current tax expense of $15.1$24.9 million includes a $1.7$4.4 million unfavorablefavorable oil price adjustment as a result of the change in value of the government’sgovernment of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $13.4$29.3 million for the period.
As of September 30, 2021,2022, the Company had 0no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.
In connection with the Arrangement with TransGlobe, the Company anticipates that a Section 382 change of ownership will result although it is not anticipated that this change will have any material impact on the Company’s financial statements.
ITEM 2. MANAGEMENT’SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SPECIAL NOTE
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:
the impact of the coronavirus (“COVID-19”) pandemic, including its impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity when and if needed, disruptions in global supply chains, quarantines of our workforce or workforce reductions and other matters related to the pandemic;
● | the impact of the coronavirus (“COVID-19”) pandemic, including its impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity when and if needed, disruptions in global supply chains, quarantines of our workforce or workforce reductions and other matters related to the pandemic; |
● | the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries (collectively, “OPEC+”) with respect to crude oil production levels; |
● | volatility of, and declines and weaknesses in crude oil and natural gas prices, as well as our ability to offset volatility in prices through the use of hedging transactions; |
● | our ability to effectively integrate and realize the anticipated benefits and synergies expected from the Arrangement with TransGlobe Energy Corporation (“TransGlobe”); |
● | our ability to generate sufficient cash to satisfy TransGlobe’s payment obligations under the Merged Concession Agreement or be able to collect some or all of TransGlobe’s receivables from the EGPC; |
● | our ability to effectively operate in and satisfy legal requirements in new jurisdictions following the Arrangement; |
● | the discovery, acquisition, development and replacement of crude oil and natural gas reserves; |
● | impairments in the value of our crude oil and natural gas assets; |
● | future capital requirements; |
● | our ability to maintain sufficient liquidity in order to fully implement our business plan; |
● | our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements; |
● | the ability of the BWE Consortium of VAALCO, BW Energy and Panoro Energy to successfully execute its business plan; |
● | our ability to attract capital or obtain debt financing arrangements; |
● | our ability to pay the expenditures required in order to develop certain of our properties; |
● | operating hazards inherent in the exploration for and production of crude oil and natural gas; |
● | difficulties encountered during the exploration for and production of crude oil and natural gas; |
● | the impact of competition; |
● | our ability to identify and complete complementary opportunistic acquisitions; |
● | our ability to effectively integrate assets and properties that we acquire into our operations; |
● | weather conditions; |
● | the uncertainty of estimates of crude oil and natural gas reserves; |
● | currency exchange rates and regulations; |
● | unanticipated issues and liabilities arising from non-compliance with environmental regulations; |
the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries (collectively, “OPEC+”) with respect to crude oil production levels;
volatility of, and declines and weaknesses in crude oil and natural gas prices, as well as our ability to offset volatility in prices through the use of hedging transactions;
the discovery, acquisition, development and replacement of crude oil and natural gas reserves;
impairments in the value of our crude oil and natural gas assets;
future capital requirements;
our ability to maintain sufficient liquidity in order to fully implement our business plan;
our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;
the ability of the consortium to successfully execute its business plan;
our ability to attract capital or obtain debt financing arrangements;
our ability to pay the expenditures required in order to develop certain of our properties;
operating hazards inherent in the exploration for and production of crude oil and natural gas;
difficulties encountered during the exploration for and production of crude oil and natural gas;
the impact of competition;
our ability to identify and complete complementary opportunistic acquisitions;
our ability to effectively integrate assets and properties that we acquire into our operations;
weather conditions;
the uncertainty of estimates of crude oil and natural gas reserves;
currency exchange rates and regulations;
unanticipated issues and liabilities arising from non-compliance with environmental regulations;
the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;
the availability and cost of seismic, drilling and other equipment;
difficulties encountered in measuring, transporting and delivering crude oil to commercial markets;
our ability to effectively replace the floating, production, storage and offloading vessel (“FPSO”);
timing and amount of future production of crude oil and natural gas;
hedging decisions, including whether or not to enter into derivative financial instruments;
general economic conditions, including any future economic downturn, disruption in financial markets and the availability of credit;
our ability to enter into new customer contracts;
● | the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon; |
● | the availability and cost of seismic, drilling and other equipment; |
● | difficulties encountered in measuring, transporting and delivering crude oil to commercial markets; |
● | our ability to effectively replace the floating, production, storage and offloading vessel (“FPSO”); |
● | timing and amount of future production of crude oil and natural gas; |
● | hedging decisions, including whether or not to enter into derivative financial instruments; |
● | general economic conditions, including any future economic downturn, the impact of inflation, disruption in financial markets and the availability of credit; |
● | our ability to enter into new customer contracts; |
● | changes in customer demand and producers’ supply; |
● | actions by the governments of and events occurring in the countries in which we operate; |
● | actions by our joint venture owners; |
● | compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change; |
● | the outcome of any governmental audit; and |
● | actions of operators of our crude oil and natural gas properties. |
changes in customer demand and producers’ supply;
actions by the governments of and events occurring in the countries in which we operate;
actions by our joint venture owners;
compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;
the outcome of any governmental audit; and
actions of operators of our crude oil and natural gas properties.
The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 20202021 (“20202021 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the 20202021 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.
Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this “Special Note“Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements 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 occurring after the date of this Quarterly Report.
INTRODUCTION
VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration and development activities in Gabon, West Africa. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa.
Following the Arrangement with TransGlobe, discussed below, we now have assets in Egypt and Canada.
As discussed further in Note 3 to the condensed consolidated financial statements included in this Quarterly Report, we have discontinued operations associated with our activities in Angola, West Africa.
A significant component
RECENT DEVELOPMENTS
TransGlobe Merger
On October 13, 2022, VAALCO Energy, Inc. (“VAALCO”) and VAALCO Energy Canada ULC (“AcquireCo”), an indirect wholly-owned subsidiary of VAALCO, completed the previously announced business combination with TransGlobe Energy Corporation (“TransGlobe”) whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares (the “Arrangement”) and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to an arrangement agreement entered into by VAALCO, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”).
At the effective time of the Arrangement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive 0.6727 (the “exchange ratio”) of a share of common stock, par value $0.10 per share, of VAALCO (“VAALCO common stock,” and each share of VAALCO common stock, a “VAALCO share”). The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. The Arrangement resulted in VAALCO stockholders owning approximately 54.5%, and TransGlobe shareholders owning approximately 45.5% of the combined company (the “Combined Company”), calculated based on vested outstanding shares of each company as of the date of the Arrangement Agreement. The post-Arrangement results of operations is dependent uponof VAALCO and TransGlobe for the difference between prices receivedfourth quarter of 2022 will be included in the Company’s consolidated results for our offshore Gabon crude oil productionthe period ending December 31, 2022.
Additionally, prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and the costs to find and produce such crude oil. Historically, crude oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control. In 2020, crude oil and natural gas prices experienced an unprecedented decline due to a combination of factors, including a substantial decline in global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million.
For the three and nine months ended September 30, 2021, crude oil prices have improved, there have been no disruptions2022 included in the line item "Other (expense) income, net" is $6.4 million and $7.6 million of transactions costs, respectively, associated with the Arrangement with TransGlobe.
Entry into a Facility Agreement
On May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”), a wholly owned subsidiary of VAALCO, entered into a facility agreement (the “Facility Agreement”) by and among VAALCO, VAALCO Gabon, SA (“VAALCO Gabon” and, together with VAALCO, the “Guarantors”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an aggregate maximum principal amount of up to operations since$50.0 million. Subject to certain conditions, the beginningBorrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the pandemic, global economic activity has steadilyFacility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million. See “Capital Resources and oil demand has stabilized over multiple quarters, removing muchLiquidity – RBL Facility Agreement” for more information regarding the Facility.
Marine Construction Agreement for Subsea Reconfiguration
On March 17, 2022, VAALCO Gabon, SA (“VAALCO Gabon”), a wholly owned subsidiary of VAALCO, entered into an Agreement for the Provision of Subsea Construction and Installation Services (the “Marine Construction Agreement”) with DOF Subsea Canada Corp. (“DOF Subsea”), to support the subsea reconfiguration in connection with the replacement of the uncertaintythen-existing FPSO vessel with a Floating Storage and instabilityOffloading vessel (“FSO”) at the Etame Marin field offshore Gabon. Pursuant to the Marine Construction Agreement, DOF Subsea agreed to, among other things, provide all personnel, crew and equipment necessary to assist in the industry. The continued spreadreconfiguration of COVID-19, including vaccine-resistant strains, or repeated deteriorationthe Etame field subsea infrastructure to accommodate all field production to the flow to the FSO, which conversion included (i) assistance with retrieval of over 5,000 meters of new flexible pipelines from a manufacturing facility in crude oilthe United Kingdom, transporting the pipelines to Gabon and natural gas prices could resultinstalling the pipelines in additional adverse impacts on the Company’s results of operations, cash flowsEtame field, (ii) performing the retrieval and financial position, including further asset impairments. Despite these challenges, we remain committed to generating long-term value for our stockholders by focusing on exploration and developmentrelocation of existing properties, adding value with accretive acquisitions, controlling costsin-field flowlines and optimizing production.umbilicals to accommodate the reconfigured field development plan and (iii) assistance in the connection of new risers to the FSO (collectively, the “Services”). Pursuant to the Marine Construction Agreement, DOF Subsea provided an offshore construction vessel to facilitate the performance of the Services. In October 2022, we completed the FSO installation and field reconfiguration at Etame field.
RECENT DEVELOPMENTSRecent Operational Updates
Provisional Award of Two Offshore Blocks in Gabon
The
On October 11, 2021 we announced our entry into a consortium of VAALCO,with BW Energy and Panoro Energy were(the “BWE Consortium”) and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of production sharing contracts (“PSCs”) with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13 are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.
The two blocks will be held by the consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by a further two years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling one exploration well on each of the two blocks. In the event the consortium elects to enter the second exploration period, the consortium will be committed to drilling at least another exploration well on each of the awarded blocks.
Charter Agreement for the Floating Storage and Offloading Unit
We
In August of 2021, we and our co-venturers at Etame approved the Bareboat Contract (the “Bareboat Contract”) and Operating Agreement (collectively,(the “Operating Agreement” and collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. (“World Carrier”) to replace the existing Floating Production, Storage and Offloading unit (“FPSO”)FPSO with a Floating Storage and Offloading unit (“FSO”).an FSO. The FSO Agreements requirerequired a prepayment of $2 million gross ($1.3 million net) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. Current total field level capital conversion estimates are $40$70 to $50$86 million gross ($2645 to $32$55 million net to VAALCO).
The FPSO charter we were party to prior to the FSO installation was set to expire in September 2022, but on September 9, 2022 we signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022, and ratified certain decommissioning and demobilization items associated with about $5exiting the contract. Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022 and other demobilization fees totaling $15.3 million on a gross basis ($8.9 million net expected in 2021 andto VAALCO Gabon).
On October 19, 2022, the remainder in 2022.
Impact on Operations of COVID-19 Pandemic and the Current Crude Oil Pricing Environment
On March 11, 2020, the World Health Organization classified the outbreak of a new strain of coronavirus (“COVID-19”) as a pandemic, based on the rapid increase in global exposure. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. The adverse economic effectsreplacement of the COVID-19 outbreak materially decreased demand for crudeexisting FPSO was completed and we signed the final acceptance certificate, at which time control of the vessel transferred to the Company. The new FSO has been named “Teli” (renamed from “Cap Diamant”) and is on site and accepting oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices in 2020. In April 2020, countries within OPEC+, which includes Gabon, reached an agreement to cut crude oil production to reduce the gap between excess supply and demand, in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement and, as a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production. In response to such request from the Minister of Hydrocarbons, beginning in July 2020 and continuing through April 2021, we temporarily reduced production fromat the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. Reductions in production have significantly improved the demand/supply imbalance, and crude oil prices have improved from the lows seen in March and April of 2020. As a result, in July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. See “Liquidity” below for discussion of the unexpired commodity swaps we have in place.
While crude oil prices are currently at the highest levels seen in recent years, the continued spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in crude oil and natural gas prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including further asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.
Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.
In response to the COVID-19 outbreak and the current pricing environment, we took the following measures:
put in place social distancing measures at our work sites;
actively screened and monitored employees and contractors that come on to our facilities including testing and quarantines with onsite medical supervision;
engaged in regular company-wide COVID-19 updates to keep employees informed of key developments;
implemented sharing certain costs, such as supply vessels, helicopter, and personnel with other operators in the region.
We expect to continue to take proactive steps to manage any disruption in our business caused by COVID-19 and to protect the health and safety of our employees. However, the health and safety measures we and our vendors have taken have resulted in us incurring higher costs. As a result of these factors and the conditions described above, 2020 was one of the most uncertain and disruptive years that the industry has ever seen and while the business environment in 2021 appears to be improving, the situation remains fluid. Accordingly, the results presented herein are not necessarily indicative of future operating results.
Recent Operational Updates
In December 2020, we completed the acquisition of approximately 1,000 square kilometers of new dual-azimuth proprietary 3-D seismic data over the entire Etame Marin block and have now processed the new 3-D seismic which has allowed us to optimize drilling locations for the 2021/2022 drilling campaign. The seismic data enhanced sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. Drilling Campaign
In conjunction with the 2021/2022 drilling program, expected to beginthat began in December 2021, we have executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling
Limited, to drill foura minimum of three wells with options to drill additional wells. We expect to spudOn October 4, 2021, we novated the Borr Jack-Up XIV Inc contract with Borr West Africa Assets, Inc. In December of 2021, we spudded the Etame 8H side track,8H-ST, the first well of the 2021/2022 drilling program,program. In February of 2022 we completed the drilling of the Etame 8H-ST well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST development well, which targeted the Gamba reservoir. The Etame 8H-ST demonstrated an initial flow rate of approximately 5,000 gross barrels of oil per day BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. In April 2022, the Avouma 3H-ST well was completed and brought online with an initial production rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022.
In July 2022 we completed the South Tchibala 1HB-ST ("ETBSM 1HB-ST") well on the Avouma platform, targeting the Gamba reservoir and also testing the Dentale formation. The section of the Gamba sand encountered was not economically viable to complete in this wellbore. However, we did discover two potential zones, the Dentale D1 and Dentale D9 zones for development. The well was completed in the Dentale D1 formation and brought online in July with an initial production rate of approximately 293-390 gross BOPD, 150-200 BOPD net to VAALCO’s 58.8% working interest in 2022. The Dentale D9 well is temporarily shut-in, however; we plan to evaluate and recomplete the D9 zone during the next drilling campaign.
Following the completion of the ETBSM 1HB-ST well, the rig was mobilized to the Southeast Etame North Tchibala Platform to drill the North Tchibala 2H-ST ("ETBSM 2H-ST") well, targeting the Dentale formation, which is productive in other areas in the Etame license. After setting up the equipment and completing operations to re-enter the well, VAALCO began drilling the ETBSM 2H-ST well on August 8th. On September 27, 2022, we announced successful drilling of the ETBSM 2H-ST well. The well encountered nearly 100 meters of gross Dentale pay sands (72 meters net). The ETBSM 2H-ST well is currently in the process of cleaning up as operational activities on and around the platform delayed the ability to flow the well soon after it completed drilling.
We recently utilized the rig to perform a workover on the North Tchibala 1-H well due to a safety valve in the well that required replacement. With the rig already on site it was easier and more economic to utilize the rig to complete the workover following the completion of the ETBSM 2H-ST well. The final well operation planned for the rig is another workover, the South East Etame 4-H (“ETSEM-4H”) well, which is expected to restore production to 1,000 and 1,500 gross BOPD upon completion. This well went offline in early December.September as a result of an upper electric submersible pump (“ESP”) failure and we were unable to restart the upper ESP or the lower ESP to restore production. Utilizing the rig for the workovers instead of new wells that were previously planned has reduced the total cost of the 2021/2022 drilling campaign at Etame.
We estimate the range of cost of the current 2021/2022 drilling program with four wells and two workovers to be between $117.0$165 million to $143.0$202 million gross, or $74.0$104 million to $91.0$128 million, net to VAALCO’s 63.6% participating interest with about $26$25 million to about $31 million gross expected in 2021,the last quarter of 2022, or about $16 million to $20$19 million net to VAALCO.
Workovers
In October 2021, we completed two workovers on the Ebouri 2-H and the Etame 12-H wells. The workover on the Ebouri 2-H well increased production from about 500 gross barrels of oil per day (“BOPD“)(255 BOPD, net) prior to the workover to approximately 1,400 gross BOPD (715 BOPD, net). For the Etame 12-H well, we replaced both the upper and lower electrical submersible pumps (“ESP”) and reconfigured the ESP design resulting in restored production of about 1,800 gross BOPD (920 BOPD, net).
Acquisition of Additional Working Interest at Etame Marin Block
In November 2020, we signed a sale and purchase agreement (“SPA”('SPA") to acquire Sasol Gabon S.A.’s (“Sasol’s” ("Sasol’s") 27.8% working interest in the Etame Marin block offshore Gabon (the “Sasol Acquisition”).Gabon. On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA.SPA (the "Sasol Acquisition"). The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items were recorded at their fair value. As a resultSee Note 3 for further information.
The actual impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $26.4 million and $58.0 million for the three and nine months ended September 30, 2021, respectively, and a $10.2 million and $20.1 million increase to “Net income” in the condensed consolidated statement of operations for the three and nine months ended September 30, 2021, respectively. Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, we paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.
ACTIVITIES BY ASSET
Gabon
Gabon
Offshore – Etame Marin Block
Development and Production
We operate the Etame Marin Block on behalf of a consortium of companies. As of September 30, 2021,2022, production operations in the Etame Marin block included eleven platform wells, plus three subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the crude oil from a leased FPSO anchored to the seabed on the block. We currently haveblock giving us a total of fourteen producing wells. The FPSO has production limitations of approximately 25,000 barrels of oil per day and 30,000 barrels of total fluids per day. During the three months ended September 30, 20212022 and 2020,2021, production from the block was 1,3841,647 MBbls (708(842 MBbls net) and 1,5001,284 MBbls (405(708 MBbls net), respectively, as discussed below in “Results“Results of Operations”Operations”. During the nine months ended September 30, 20212022 and 2020,2021, production from the Etame Marin block was 4,701 MBbls (2,405 MBbls net) and 4,063 MBbls (1,904 MBbls net) and 4,987 MBbls (1,347 MBbls net), respectively, as discussed below in “Results of Operations”.respectively.
Equatorial Guinea
Our working interest will increase to 45.9% once the EG MMHMinistry of Mines and Hydrocarbons (“EG MMH”) approves a new amendment to the production sharing contract. As of September 30, 2021,2022, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. We have completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. We are now proceedingOn July 15, 2022 VAALCO, on behalf of itself and Guinea Ecuatorial de Petroleós (“GEPetrol”), submitted to the EG MMH a fieldplan of development concept and will work closely withfor the Venus development in Block P. The other Block P joint venture ownersowner, Atlas Petroleum International Limited, did not participate in the submission. On September 26, 2022, the EG MMH approved the submitted plan of development. Final documents to complete this overeffect the coming months.plan of development are subject to EG MMH approval and are under negotiations among all parties. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.
TableDISCONTINUED OPERATIONS-ANGOLA
In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of Contents
Discontinued Operations -the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola,
The we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the condensed consolidated financial statementsFinancial Statements for all periods presented. See Note 3 to the condensed consolidatedFinancial Statements. For the three and nine months ended September 30, 2022 and 2021, the Angola segment did not have a material impact on our financial statements for further discussion.position, results of operations, cash flows and related disclosures.
CAPITAL RESOURCESAND LIQUIDITY
Cash Flows
Our cash flows for the nine months ended September 30, 20212022 and 20202021 are as follows:
Nine Months Ended September 30, | ||||||||||||
2022 | 2021 | Increase (Decrease) in 2022 over 2021 | ||||||||||
(in thousands) | ||||||||||||
Net cash provided by operating activities before changes in operating assets and liabilities | $ | 95,850 | $ | 44,287 | $ | 51,563 | ||||||
Net change in operating assets and liabilities | 33,906 | 2,506 | 31,400 | |||||||||
Net cash provided by continuing operating activities | 129,756 | 46,793 | 82,963 | |||||||||
Net cash used in discontinued operating activities | (57 | ) | (72 | ) | 15 | |||||||
Net cash provided by operating activities | 129,699 | 46,721 | 82,978 | |||||||||
Net cash used in investing activities | (103,853 | ) | (30,964 | ) | (72,889 | ) | ||||||
Net cash used in financing activities | (8,075 | ) | (121 | ) | (7,954 | ) | ||||||
Net change in cash, cash equivalents and restricted cash | $ | 17,771 | $ | 15,636 | $ | 2,135 | ||||||
Nine Months Ended September 30, | |||||||||
2021 | 2020 | Increase (Decrease) in 2021 over 2020 | |||||||
(in thousands) | |||||||||
Net cash provided by operating activities before changes in operating assets and liabilities | $ | 43,111 | $ | 22,466 | $ | 20,645 | |||
Net change in operating assets and liabilities | 3,682 | (3,029) | 6,711 | ||||||
Net cash provided by continuing operating activities | 46,793 | 19,437 | 27,356 | ||||||
Net cash used in discontinued operating activities | (72) | (376) | 304 | ||||||
Net cash provided by operating activities | 46,721 | 19,061 | 27,660 | ||||||
Net cash used in investing activities | (30,964) | (22,317) | (8,647) | ||||||
Net cash used in continuing financing activities | (121) | (990) | 869 | ||||||
Net cash used in financing activities | (121) | (990) | 869 | ||||||
Net change in cash, cash equivalents and restricted cash | $ | 15,636 | $ | (4,246) | $ | 19,882 | |||
The $20.6$51.6 million increase in net cash provided by our operating activities, before changes in operating assets and liabilities for the nine months ended September 30, 2021 comparedwas due to the same period of 2020, was mainly due to higher crude oil priceschange in 2021the bargain purchase gain, the change in depreciation, the change in losses on derivative instruments and the change in deferred taxes (collectively $92.8 million) partially offset by the changes cash settlement in impairment, deferred taxesderivative contracts and derivatives.lower net income and other changes (collectively ($41.2) million). The net increase in changes provided by operating assets and liabilities of $6.7$31.4 million for the nine months ended September 30, 20212022 compared to the same period of 20202021 was primarily related to increases in accounts payable, accrued liabilities and foreign income taxes payable (collectively $65.6 million) partially offset by changes in foreign taxes payable as a result of the in-kind lifting tax payment valued at $20.1accounts receivable with joint venture owners, trade receivables, crude oil inventory and other changes (collectively ($34.2) million).
The $72.9 million increase in September 2021 and accrued liabilities as a result of starting the 2021/2022 drilling campaign.
Netnet cash used in investing activities during the nine months ended September 30, 2021 included $22.5 million paid2022 was due to increases in capital spending in 2022 for the completion ofEtame 8-H well, the Sasol Acquisition as discussed in Note 3Avouma 3H-ST well, South Tchibala 1HB-ST well, the Etame field reconfiguration, North Tchibala 2H-ST well and other items to our condensed consolidated financial statements. In addition, we incurred on a cash basis $8.5 million for property and equipment primarily related to equipment and enhancements as well as expenditures related tosupport the next2021/2022 drilling program as discussed in “Recent Operational Updates” above. Duringcampaign. For the nine months ended September 30, 2020, we incurred on a2021, net cash basis $22.3 million for expenditures relatedused in investing activities was mainly due to cash used in the 2019/2020 drilling campaign and equipment purchases. See “Capital Expenditures”below for further discussion.purchase of Sasol’s interest in the Etame Block.
Net cash used in financing activities during the nine months ended September 30, 20212022 included $1.4$5.8 million for dividend distributions, $0.8 million for treasury stock repurchases, as a result of tax withholding on options exercised and on vested restricted stock as discussed in Note 1415 to our condensed consolidated financial statements, $1.5 million of costs capitalized associated with our credit facility and $0.2 million of principal payments on our finance leases partially offset by $1.3$0.3 million in proceeds from options exercised. Net cash used in financing activities during the nine months ended September 30, 2020 included $1.0 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.
Capital Expenditures
DuringFor the nine months ended September 30, 2021, cash used in financing activities was mainly due to cash used in the purchase of treasury shares partially offset by proceeds received from options exercised.
Capital Expenditures
For the nine months ended September 30, 2022 we incurredhad accrual basis capital expenditures attributable to continuing operations of $121.6 million compared to $11.0 million. Thesemillion accrual basis capital expenditures for the same period in 2021, excluding the Sasol Acquisition. For the nine months ended September 30, 2022, our efforts were primarily related to equipment and enhancements, as well as expendituresfocused on spending related to the next2021/2022 drilling program. The difference between capital expenditurescampaign and Etame field reconfigurations and FSO projects. During the property and equipment expenditures reportedsame period in the condensed consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid2021, our spending was concentrated on the report dates. Sasol Acquisition and obtaining certain long lead items for the 2021/2022 drilling campaign.
See discussion below in “Capital expenditures in 2020 were attributable to expenditures related to the 2019/2020 drilling programResources, Liquidity and equipment and enhancements. As discussed above, we anticipate beginning a drilling program late in 2021 that will continue into 2022, at an estimated cost of $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest with about $26 million to about $31 million gross expected in 2021, or about $16 million to $20 million net to VAALCO. In April 2021, we purchased a workover unit to have on siteCash Requirements” for approximately $1.9 million for future maintenance work.further information.
Contractual Obligations
See Notes 10 and 11 to the condensed consolidated financial statements in this quarterly report as well as Notes 12 and 13 to our 2020 Form 10-K for discussion of our contractual obligations.
Regulatory and Joint Interest Audits
We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum cost account,Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 10 to the condensed consolidated financial statementsFinancial Statements for further discussion.
Commodity Price Hedging
The price we receive for our crude oil significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Crude oil commodities and, therefore their prices can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future.
Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps and costless collars to hedge price risk associated with a portion of our anticipated crude oil production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the condensed consolidated statement of operations. We record such derivative instruments as assets or liabilities in the condensed consolidated balance sheet.
See the table below for the unexpired contracts.
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||||||||
(Bbls) | (per Bbl) | (per Bbl) | ||||||||||||||
October 2022 to December 2022 | Collars | Dated Brent | 109,000 | $ | 70.00 | $ | 122.00 | |||||||||
Pursuant to the Facility entered into in May 2022, we are required to hedge a portion of our anticipated oil production at the time we draw down on the Facility.
Subsequent Event
On October 26, 2022, we entered into additional derivatives contracts for the first quarter of 2023. The details are in the chart below:
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||
January 2023 to March 2023 | Collars | Dated Brent | 101,000 | $ 65.00 | $ 120.00 |
Cash on Hand
At September 30, 2022, we had unrestricted cash of $69.3 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.
We currently sell all our crude oil production from Gabon under a crude oil sales and marketing agreement ("COSMA") with Glencore. Under the COSMA all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the Final Maturity Date of the Facility, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Capital Resources, Liquidity and Cash Requirements
Historically, our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. For example, we recently took actions to improve our liquidity position by entering into the Facility Agreement. We believe that the recent Facility significantly improves our financial flexibility and our ability to achieve accretive growth by providing access to cash if required for potential future development programs or to fund inorganic acquisition opportunities. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support our current cash requirements, including those related to our 2021/2022 drilling program and our ability to fund any remaining decommissioning or demobilization costs relating to the FPSO, the FSO charter, as well as transaction expenses and operational costs associated with the TransGlobe acquisition, through December 2023. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.
Merged Concession Agreement
On January 19, 2022, subsidiaries of TransGlobe executed an agreement (the “Merged Concession Agreement”) with the Egyptian General Petroleum Corporation (“EGPC”) to update and merge TransGlobe’s three Egyptian concessions in West Bakr, West Gharib and NW Gharib (the “Merged Concession”). The modernization payments under the Merged Concession Agreement total $65.0 million and are payable over six years from the Merged Concession Effective Date. Under the agreement, TransGlobe will be required to pay an additional $10.0 million on February 1st for each of the next four years. In addition, TransGlobe has committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (totalling $150.0 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which is subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.
RBL Facility Agreement and Available Credit
On May 16, 2022, VAALCO Gabon (Etame), Inc. entered into Facility Agreement by and among VAALCO, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C. and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million. Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.
The Facility provides for determination of the borrowing base asset based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is determined and redetermined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.
The Borrower’s obligations under the Facility Agreement are guaranteed by Guarantors and secured by interests, rights, activities, assets, entitlements, and development in the Etame Marin Permit (Block G64-160) Field and any other assets which are approved by the Majority Lenders (as defined in the Facility Agreement).
Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).
Pursuant to the Facility Agreement, we shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.
The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of September 30, 2022, our borrowing base was $50.0 million. The amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. We were in compliance with all debt covenants at September 30, 2022. As of September 30, 2022, we had no outstanding borrowings under the facility.
The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).
In connection with the merger with TransGlobe in October 2022, prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million.
Cash Requirements
Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the Sasol Acquisition, the TransGlobe acquisition transaction costs, and abandonment funding, each of which is discussed in further detail below.
Sasol Acquisition – As a result of completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in the Etame have increased based on the increase in our working interest in the Etame from 31.1 % at December 31, 2020, to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February 25, 2021.
FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement with World Carrier to replace the existing FPSO with a FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the Teli vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions. Pursuant to the Operating Agreement, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO. As consideration for the performance by World Carrier of the Operator Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Operating Agreement) until the end of the term, with such term being the same as the term in the Bareboat Charter.
The FSO Agreements require a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. In addition, VAALCO Gabon agreed to pay a daily hire rate at certain rates specified therein, with such hire rate being based on the year within the term.
In connection with the implementation of the FSO, we are required to incur certain Etame field configuration expenses in order to facilitate the FSO. Current total field conversion estimates are $70 to $86 million gross ($45 to $55 million net to VAALCO).
The FPSO charter we were party to prior to the FSO installation was set to expire in September 2022, but on September 9, 2022, we signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022, and ratified certain decommissioning and demobilization items associated with exiting the contract. Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022 and other demobilization fees totaling $15.3 million on a gross basis ($8.9 million net to VAALCO Gabon).
BWE Consortium – On October 11, 2021, we announced our entry into a consortium with BW Energy and Panoro Energy and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of the PSC with the Gabonese government. BW Energy will be the operator with a 37.5% working interest. We will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by an additional two more years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.
Drilling Program – We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8H-ST development well. In February of 2022 we completed the drilling of the Etame 8H-ST well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST development well, which targeted the Gamba reservoir. The initial flow rate of the ETAME 8H-ST well was 5,000 gross barrels of oil per day ("BOPD"), 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. In April 2022, the Avouma 3H-ST well was completed and brought online with an initial production rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022. In September 2022, we successfully drilled the North Tchibala 2H-ST well that was drilled from the Southeast Etame North Tchibala platform in the Etame field, offshore Gabon and we are preparing to complete the well utilizing a fracture stimulation vessel that will provide support with multiple stimulation and frac-pack operations.
In July 2022 we completed the ETBSM 1HB-ST well on the Avouma platform, targeting the Gamba reservoir and also testing the Dentale formation. The section of the Gamba sand encountered was not economically viable to complete in this wellbore. However, we did discover two potential zones, The Dentale D1 and Dentale D9 zones for development. The well was completed in the Dentale D1 formation and brought online in July with an initial production rate of approximately 293-390 gross BOPD, 150-200 BOPD net to VAALCO’s 58.8% working interest in 2022. The Dentale D9 well is temporarily shut-in, however; we plan to evaluate and recomplete the D9 zone during the next drilling campaign.
Following the completion of the ETBSM 1HB-ST well, the rig was mobilized to the Southeast Etame North Tchibala Platform to drill the North Tchibala ("ETBSM") 2H-ST well, targeting the Dentale formation, which is productive in other areas in the Etame license. This mobilization was delayed by two weeks due to weather and the rig began operations on the well in late July. After setting up the equipment and completing operations to re-enter the well, VAALCO began drilling the ETBSM 2H-ST well on August 8, 2022. The well is currently in the process of cleaning up as operational activities on and around the platform delayed the ability to flow the well soon after it completed drilling.
We recently utilized the rig to perform a workover on the North Tchibala 1-H well due to a safety valve in the well that required replacement. With the rig already on site it was easier and more economic to utilize the rig to complete the workover following the completion of the North Tchibala 2H-ST well. The final well operation planned for the rig is another workover, the ETSEM-4H well, which is expected to restore production to 1,000 and 1,500 gross BOPD upon completion. This well went offline in early September as a result of an upper ESP failure and we were unable to restart the upper ESP or the lower ESP to restore production. Utilizing the rig for the workovers instead of new wells that were previously planned has reduced the total cost of the 2021/2022 drilling campaign at Etame.
In July 2022, we elected to exercise our options on the rig contract time to allow us to perform two workovers. We expect to release the drilling rig in November 2022.
We estimate the range of cost of the 2021/2022 drilling program with four wells and two workovers to be between $165 million to $202 million gross, or $104 million to $128 million, net to VAALCO’s participating interest with $25 million to $31 million gross expected in the last quarter of 2022, or $16 million to $19 million net to VAALCO.
TransGlobe Merger – On October 13, 2022, the Company and AcquireCo completed the business combination with TransGlobe. At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to receive 0.6727 of a share of VAALCO common stock. The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million.
Dividend Policy – On November 3, 2021, we announced that our board of directors adopted of a quarterly cash dividend policy of an expected $0.0325 per common share per quarter, commencing in the first quarter of 2022.
On March 18, 2022, we paid a quarterly cash dividend of $0.0325 per share of common stock to the stockholders of record at the close of business on February 18, 2022. On June 24, 2022, we paid a quarterly cash dividend of $0.0325 per share of common stock to the stockholders of record at the close of business on May 25, 2022. On August 5, 2022, we announced that the board of directors had declared a quarterly cash dividend of $0.0325 per share of common stock, payable on September 23, 2022 to stockholders of record at the close of business on August 24, 2022. On October 31, 2022, we announced a quarterly cash dividend of $0.0325 per share of common stock for the fourth quarter of 2022 which is payable December 22, 2022 to stockholders of record at the close of business on November 22, 2022.
In connection with the Arrangement with TransGlobe, we announced our intention, following consummation of the Arrangement, we would seek to have an annualized dividend target of $28 million for 2023, or approximately $0.25 per share (calculated based the estimated combined outstanding shares after the merger), with payments to be made quarterly.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Share Buyback Program – On November 1, 2022, we announced that our newly-expanded board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with the Company’s business combination with TransGlobe. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “Plan”) to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.
Shares may be repurchased from time-to-time in open market transactions at prevailing market prices, in privately negotiated transactions or by other means in accordance with federal securities laws, including Rule 10b5-1 programs, and the Share Buyback Program may be suspended or discontinued at any time. The actual timing, number and value of shares repurchased will be determined by a committee of the board of directors at its discretion and will depend on a number of factors, including the market price of VAALCO’s common stock, general market and economic conditions, alternative investment opportunities and other corporate considerations.
Trends and Uncertainties
COVID-19 Pandemic – While crude oil prices are currently at the highest levels seen in recent years, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude oil and natural gas prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.
War with Ukraine and Other Market Forces – The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The ongoing conflict has caused, and could intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.
During the three and nine months ended September 30, 2022, for example, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities has lengthened and, in some cases, prices for materials have increased. Management believes the ongoing war between Russia and Ukraine and its related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.
Commodity Prices– Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil prices, a decrease in demand for crude oil and future production cuts by OPEC+. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts by September 2022. However, as a result of the recent decline in oil prices, on October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. To date, we have not received any mandate to reduce our current oil production from the Etame Marin block as a result of the OPEC+ initiative. Brent crude prices were approximately $88.90 per barrel as of September 30, 2022.
ESG and Climate Change Effects
Environmental, social and governance (“ESG”) – ESG matters continue to attract considerable public and scientific attention. In particular, we expect continued regulatory attention on climate change issues and emissions of greenhouse gases (“GHGs”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion). This increased attention to climate change and environmental conservation may result in demand shifts away from crude oil and natural gas products to alternative forms of energy, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investors’ investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG standards, including the reduction of our carbon footprint and measurement of GHG emissions.
Capital Resources
Cash on Hand
At September 30, 2021, ESG is important to us, and we had unrestricted cash of $52.8 million. The unrestricted cash balance includes $2.3 million of cash attributable to non-operating joint venture owner advances. As operator of the Etame Marin block in Gabon, we enter into project related activities on behalf of our working interest joint venture owners. We generally obtain advances from the joint venture owners prior to significant funding commitments.
We currently sell our crude oil production from Gabon under a term contract that began in February 2020 and, after contract extensions, ends on January 31, 2022. Pricing under the contract is based upon an average of Dated Brentare in the monthprocess of lifting, adjusted for locationdeveloping a multi-year plan to establish and market factors. See Note 8document our ESG base currently and developing a systematic plan to monitor and improve matters related to ESG and climate change going forward.
Hedging
We seek to mitigate the condensed consolidated financial statements for further discussion.
Liquidity
Historically, our primary sourceimpact of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activitiesvolatility in the Etame Marin block. As a result of completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in the Etame have increased based on the increase in our working interest in the Etame from 31.1 % at December 31, 2020, to 58.8%. We expect that part of this increase will be offset by an increase in our operating cash flows based on our increased portion of the Etame production. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions.
Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us. In 2020, crude oil prices experienced a significant decline as a result ofthrough hedging. See the substantial decline intable below for the global demand for crude oil caused byunexpired contracts.
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||||||||
(Bbls) | (per Bbl) | (per Bbl) | ||||||||||||||
October 2022 to December 2022 | Collars | Dated Brent | 109,000 | $ | 70.00 | $ | 122.00 | |||||||||
Pursuant to the COVID-19 pandemic and subsequent mitigation efforts. Reductions in production have significantly improved the demand/supply imbalance and crude oil prices have improved from the lows seen in March and April of 2020. Between July 2020 and April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. Brent crude prices were approximately $77 per barrel as of September 30, 2021. On January 22, 2021, weFacility entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through Januaryin May 2022, for 709,262 barrels. On May 6, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. Again, on September 24, 2021, the Company entered commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support our cash requirements, including those related to our 2021/2022 drilling program and our efforts to secure an alternative to the FPSO charter, through December 2022. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities.
Cash Requirements
Our material cash requirements generally consist of operating leases, purchase obligations, capital projects and 3D seismic processing, the Sasol Acquisition and abandonment funding. For a discussion of these cash requirements, see the information in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2020 Form 10-K, as well as the following updates.
In connection with the 2020/2021 drilling program, we estimate the range of costs for four wells to be between $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest with about $26 million to about $31 million gross expected in 2021, or about $16 million to $20 million net to VAALCO.
In connection with the FSO Agreements, we are required to makehedge a prepaymentportion of $2 million gross ($1.3 million net) in 2021 and $5 million gross ($3.2 million net) inour anticipated oil production at the time that we draw down on the Facility.
Subsequent Event
On October 26, 2022, of which $6 million will be recovered against future rentals. Current total field level capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO) with about $5 million net expected in 2021 and the remainder in 2022.
On August 2, 2021, we approved the adoption of a cash dividend policy whereby we intend to authorize the payment of quarterly cash dividends of $0.0325 per common share per quarter (full year 2022 annualized of $0.13 per share) beginning inentered into additional derivatives contracts for the first quarter of 2022.2023. The declaration of any cash dividendsdetails are in the future pursuant to VAALCO’s dividend policy will be made at the sole discretion of our Board of Directors each quarter and will depend on a number of factors, including our financial performance and available cash resources, our capital requirements, amount of legally available funds and alternative uses of cash, as well as general business conditions and legal, contractual, tax and regulatory restrictions and other factors our Board of Directors deems relevant at the time it determines to declare such dividends. Our Board of Directors expects to reassess the payment of dividends as appropriate from time to time. For these reasons, as well as others, there can be no assurance that dividends in the future will be equal or similar in amount to that described in this press release or that the Board of Directors will not decide to suspend or discontinue the payment of cash dividends in the future.chart below:
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support these cash requirements
Settlement Period | Type of Contract | Index | Average Monthly Volumes | Weighted Average Put Price | Weighted Average Call Price | |||||
January 2023 to March 2023 | Collars | Dated Brent | 101,000 | $ 65.00 | $ 120.00 |
At December 31, 2020, we had 3.2 MMBbls of estimated net proved reserves, all of which are related to the Etame Marin block offshore Gabon. In February 2021, we increased our working interest in the Etame Marin block from 31.1% to 58.8%. The current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with rights for two five-year extension periods. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. While both short-term and long-term liquidity are impacted by crude oil prices, our long-term liquidity also depends upon our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable.
OFF-BALANCE SHEET ARRANGEMENTS
None.
CRITICAL ACCOUNTING POLICIES
There have been no material changes to our critical accounting policies subsequent to December 31, 2020.2021.
NEW ACCOUNTING STANDARDS
See Note 2 to the condensed consolidated financial statements.
RESULTS OF OPERATIONS
Three Months Ended September 30, 20212022 Compared to the Three Months Ended September 30, 20202021
Net income for the three months ended September 30, 20212022 was $31.7$6.9 million compared to net income of $7.6$31.7 million for the same period of 2020.2021. See discussion below for changes in revenue and expense.
Crude oil and natural gas revenuesincreased $37.6$22.2 million, or approximately 206.2%39.7%, to $78.1 million during the three months ended September 30, 2021 compared to2022 from $55.9 million for the same period of 2020.in prior year. The increase inincreased revenue is attributable to higher sales prices and higher volumes as a result offor the Sasol Acquisition. Further discussion of results by significant line item follows.three months ended September 30, 2022 compared to the same period in 2021.
Three Months Ended September 30, | ||||||||||||
2022 | 2021 | Increase/(Decrease) | ||||||||||
(in thousands except per bbl information) | ||||||||||||
Net crude oil sales volume (MBbls) | 731 | 741 | (10 | ) | ||||||||
Average crude oil sales price (per Bbl) | $ | 103.61 | $ | 73.02 | $ | 30.59 | ||||||
Net crude oil revenue | $ | 78,097 | $ | 55,899 | $ | 22,198 | ||||||
Operating costs and expenses: | ||||||||||||
Production expense | 23,312 | 25,208 | (1,896 | ) | ||||||||
FPSO demobilization | 8,867 | - | 8,867 | |||||||||
Exploration expense | 56 | 479 | (423 | ) | ||||||||
Depreciation, depletion and amortization | 8,963 | 6,970 | 1,993 | |||||||||
General and administrative expense | 1,979 | 2,940 | (961 | ) | ||||||||
Bad debt expense | 1,020 | 318 | 702 | |||||||||
Total operating costs and expenses | 44,197 | 35,915 | 8,282 | |||||||||
Other operating expense, net | — | 46 | (46 | ) | ||||||||
Operating income | $ | 33,900 | $ | 20,030 | $ | 13,870 | ||||||
Three Months Ended September 30, | |||||||||
2021 | 2020 | Increase/(Decrease) | |||||||
(in thousands except per bbl information) | |||||||||
Net crude oil sales volume (MBbls) | 741 | 412 | 329 | ||||||
Average crude oil sales price (per Bbl) | $ | 73.02 | $ | 43.63 | $ | 29.39 | |||
Net crude oil revenue | $ | 55,899 | $ | 18,256 | $ | 37,643 | |||
Operating costs and expenses: | |||||||||
Production expense | 25,208 | 8,984 | 16,224 | ||||||
Exploration expense | 479 | 16 | 463 | ||||||
Depreciation, depletion and amortization | 6,970 | 2,212 | 4,758 | ||||||
General and administrative expense | 2,940 | 2,178 | 762 | ||||||
Bad debt expense | 318 | 151 | 167 | ||||||
Total operating costs and expenses | 35,915 | 13,541 | 22,374 | ||||||
Other operating income (expense), net | 46 | (37) | 83 | ||||||
Operating income | $ | 20,030 | $ | 4,678 | $ | 15,352 | |||
The revenue changes in the three months ended September 30, 20212022 compared to the same period in 20202021 identified as related to changes in price or volume, are shown in the table below:
(in thousands) | ||||||||||
Price | $ | 21,778 | ||||||||
Price (1) | $ | 22,361 | ||||||||
Volume | 14,354 | (730 | ) | |||||||
Other | 1,511 | 567 | ||||||||
$ | 37,643 | $ | 22,198 | |||||||
(1) | The price in the table above excludes revenues attributed to carried interests |
The table below shows net production, sales volumes and realized prices for both periods.
Three Months Ended September 30, | ||||||||
2022 | 2021 | |||||||
Gabon net crude oil production (MBbls) | 842 | 708 | ||||||
Gabon net crude oil sales (MBbls) | 731 | 741 | ||||||
Average realized crude oil price ($/Bbl) | $ | 103.61 | $ | 73.02 | ||||
Average Dated Brent spot price* ($/Bbl) | 99.90 | 73.51 | ||||||
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Three Months Ended September 30, | ||||||
2021 | 2020 | |||||
Gabon net crude oil production (MBbls) | 708 | 405 | ||||
Gabon net crude oil sales (MBbls) | 741 | 412 | ||||
Average realized crude oil price ($/Bbl) | $ | 73.02 | $ | 43.63 | ||
Average Dated Brent spot price* ($/Bbl) | 73.51 | 42.91 | ||||
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website. | ||||||
Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made three liftings during the three months ended September 30, 20212022 and three liftings during the three months ended September 30, 2020. The increase in lifting volumes is due to our increased working interest as a result of the Sasol Acquisition partially offset by natural declines in production.2021. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 98,031143,972 barrels and 36,29998,031 barrels at September 30, 2022 and 2021, and 2020, respectively.
Production expenses increased $16.2 decreased $1.9 million, or approximately 180.6%7.5%, infor the three months ended September 30, 2021 compared2022 to $23.3 million from $25.2 million for the same period in 2020.prior year. The increasedecrease in expense was primarily related to higher costs as a result of our increased working interest as a result of the Sasol Acquisition, increasedlower workover costs and changes in crude oil inventory of $7.2 million partially offset by higher marine costs.FPSO hire charges, higher boat expense, higher personnel costs and other costs of $5.3 million. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended September 30, 20212022 increased to $28.85$31.8 per barrel from $22.21$28.9 per barrel for the three months ended September 30, 20202021 primarily as a result of higher marinecharter and boat costs incurred in 2021.2022. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $0.9
$0.2 million and $0.4$0.8 million in higher costs related to the proactive measures taken in response to the pandemic for each of the three months ended September 30, 20212022 and 2020, respectively.2021.
Depreciation, depletion and amortization
FPSO demobilization costs increased $4.8 million, or approximately 215.1% due to higher depletable costs associated with the Sasol Acquisition.
General and administrative expenses increased $0.8 million, or approximately 35.0% in for the three months ended September 30, 2021 compared2022 increased to $8.9 million. These costs were incurred to retire the FPSO as we transition the block to the FSO. There were no similar expenses incurred in during the same period of 2020. The increase in 2021.
Exploration expense was primarily related to a $0.3decreased $0.4 million, decrease in SARs benefit related to SARs liability awards that are measured at fair value. The primary driver of changes in the fair value of these awards is changes in our stock price.
Bad debt expense was higher betweenor approximately 83.3% for the three months ended September 30, 2021 and 2020 primarily2022 to $0.1 million from $0.5 million for the same period in prior year. The decrease in expense is due to issues of collectabilityincurring minimal amounts for seismic processing costs for the three months ended September 30, 2022 compared to the same period in 2021 when the Company was processing the seismic data it had acquired in 2020.
Depreciation, depletion and amortization costs increased $2.0 million, or approximately 28.6% for the three months ended September 30, 2022 to $9.0 million from $7.0 million for the same period in prior year. The increase in depreciation, depletion and amortization expense is due to higher depletable costs in 2022 associated with the Value-Added Tax (“VAT”) receivable2021/2022 drilling campaign.
General and administrative expenses decreased $1.0 million, or 32.7% for the three months ended September 30, 2022 to $2.0 million from $2.9 million for the same period in Gabon.prior year. The decrease in general and administrative expense is due to higher corporate overhead allocation for the three months ended September 30, 2022 compared to the same period in 2021.
Bad debt expense increased by $0.7 million, or approximately 220.8% for the three months ended September 30, 2022 to $1.0 million from $0.3 million for the same period in prior. The increase is a result of increased spend as a result of the 2021/2022 drilling campaign. The bad debt expense and related allowance account associated with the TVA balance has also increased as we have received no payments related to these balances in 2022.
Other operating income (expense), net for the three months ended September 30, 2022 and for the three months ended September 30, 2021 and for the three months ended September 30, 2020 was not material to our results.
Derivative instruments loss,gain (loss), net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $5.1Derivative gain (loss) changed by $8.9 million, lossor approximately 173.4% to a gain of $3.8 million for the three months ended September 30, 2021 is2022 from a loss of $5.1 million during the same period in prior year. Derivative gains (losses) are a result of the continued increase in the price of Dated Brent Crude abovecrude oil over the weighted average swapinitial strike price per barrel of our derivative instruments. Forthe option over the three months ended September 30, 2020 we had no swaps2022 and 2021, respectively. Every quarter in place.2021 and continuing into 2022 Dated Brent crude oil prices have increased. During the third quarter of 2022, dated Brent crude oil prices decreased. Our current derivative instruments currently cover a portion of our production through June 2022.March 2023.
Other,
Interest income (expense), net increased $0.2 million to an expense of $0.2 million for the three months ended September 30, 20212022 from an expense of $0.0 million during the same period in 2021. Net interest expense for the three months ended September 30, 2022, includes commitments fees incurred on the Facility, amortization of debt issue costs related to the Facility and 2020 primarilyinterest associated with our finance leases partially offset by interest income.
Income tax expense (benefit) However, for the three months ended September 30, 20212022, also included in other (expense) income, net is $6.4 million of transactions costs associated with the Arrangement with TransGlobe.
Income tax expense (benefit) for the three months ended September 30, 2022 was a benefitan expense of $(17.2)$22.8 million. This is comprised of $ (22.7)current tax benefit of $1.2 million and $24.0 million of deferred tax expense. See Note 16 to the condensed consolidated financial statements for further information. Income tax expense (benefit) for the three months ended September 30, 2021 was a benefit of $17.2 million. This was comprised of $22.7 million of deferred tax benefit and a current tax expense of $5.5 million.million. The deferred income tax benefit for the three months ended September 30, 2021 included a $22.3 million deferred tax benefit from the reversal of the valuation allowance. See Note 15 to the condensed consolidated financial statements. Income tax benefit for the three months ended September 30, 2020 was a benefit of $(2.8) million and included $(5.3) million of deferred tax benefit and a current tax expense of $2.5 million. For both the three months ended September 30, 2021 and 2020, our overall effective tax rate was impacted by non-deductible items associated with operations and deducting foreign taxes rather than crediting them for United States tax purposes.
Nine Months Ended September 30, 20212022 Compared to the Nine Months Ended September 30, 20202021
Net income for the nine months ended September 30, 2021 of $47.52022 was $34.1 million compared to a net lossincome of $(44.6)$47.5 million for the same period of 2020.2021. See the discussion below for changes in revenue and expense.
Crude oil and natural gas revenues increased $88.1$115.0 million, or approximately 161.3%80.6%, to $257.7 million during the nine months ended September 30, 2021 compared to2022 from $142.7 million for the same period of 2020.in prior year 2021. The increase in revenue is attributable to more crude oil sold and higher sales prices and to a lesser degree, higher volumes. Further discussion of results by significant line item follows.Sasol’s additional working interest for the full nine months ended September 30, 2022.
Nine Months Ended September 30, | ||||||||||||
2022 | 2021 | Increase/(Decrease) | ||||||||||
(in thousands except per bbl information) | ||||||||||||
Net crude oil sales volume (MBbls) | 2,305 | 2,002 | 303 | |||||||||
Average crude oil sales price (per Bbl) | $ | 109.28 | $ | 68.31 | $ | 40.97 | ||||||
Net crude oil revenue | $ | 257,738 | $ | 142,696 | $ | 115,042 | ||||||
Operating costs and expenses: | ||||||||||||
Production expense | 67,147 | 57,760 | 9,387 | |||||||||
FPSO demobilization | 8,867 | - | 8,867 | |||||||||
Exploration expense | 250 | 1,286 | (1,036 | ) | ||||||||
Depreciation, depletion and amortization | 21,827 | 16,928 | 4,899 | |||||||||
General and administrative expense | 10,507 | 12,221 | (1,714 | ) | ||||||||
Bad debt expense | 2,083 | 814 | 1,269 | |||||||||
Total operating costs and expenses | 110,681 | 89,009 | 21,672 | |||||||||
Other operating expense, net | (5 | ) | (440 | ) | 435 | |||||||
Operating income (loss) | $ | 147,052 | $ | 53,247 | $ | 93,805 | ||||||
Nine Months Ended September 30, | |||||||||
2021 | 2020 | Increase/(Decrease) | |||||||
(in thousands except per bbl information) | |||||||||
Net crude oil sales volume (MBbls) | 2,002 | 1,337 | 665 | ||||||
Average crude oil sales price (per Bbl) | $ | 68.31 | $ | 39.90 | $ | 28.41 | |||
Net crude oil revenue | $ | 142,696 | $ | 54,619 | $ | 88,077 | |||
Operating costs and expenses: | |||||||||
Production expense | 57,760 | 30,859 | 26,901 | ||||||
Exploration expense | 1,286 | 16 | 1,270 | ||||||
Depreciation, depletion and amortization | 16,928 | 8,116 | 8,812 | ||||||
Impairment of proved crude oil and natural gas properties | — | 30,625 | (30,625) | ||||||
General and administrative expense | 12,221 | 5,951 | 6,270 | ||||||
Bad debt expense | 814 | 1,140 | (326) | ||||||
Total operating costs and expenses | 89,009 | 76,707 | 12,302 | ||||||
Other operating expense, net | (440) | (883) | 443 | ||||||
Operating income (loss) | $ | 53,247 | $ | (22,971) | $ | 76,218 | |||
The revenue changes in the nine months ended September 30, 20212022 compared to the same period in 20202021 identified as related to changes in price or volume, are shown in the table below:
(in thousands) | ||||
Price (1) | $ | 94,436 | ||
Volume | 20,698 | |||
Other | (92 | ) | ||
| $ | 115,042 |
(1) | The price in the table above excludes revenues attributed to carried interests |
(in thousands) | ||||||
Price | $ | 56,877 | ||||
Volume | 26,534 | |||||
Other | 4,666 | |||||
$ | 88,077 |
The table below shows net production, sales volumes and realized prices for both periods.periods.
Nine Months Ended September 30, | ||||||||
2022 | 2021 | |||||||
Gabon net crude oil production (MBbls) | 2,405 | 1,904 | ||||||
Gabon net crude oil sales (MBbls) | 2,305 | 2,002 | ||||||
Average realized crude oil price ($/Bbl) | $ | 109.28 | $ | 68.31 | ||||
Average Dated Brent spot price* ($/Bbl) | 105.00 | 67.89 | ||||||
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Nine Months Ended September 30, | ||||||
2021 | 2020 | |||||
Gabon net crude oil production (MBbls) | 1,904 | 1,347 | ||||
Gabon net crude oil sales (MBbls) | 2,002 | 1,337 | ||||
Average realized crude oil price ($/Bbl) | $ | 68.31 | $ | 39.90 | ||
Average Dated Brent spot price* ($/Bbl) | 67.89 | 41.15 | ||||
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website. | ||||||
Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made nine liftings during the nine months ended September 30, 2022 and eight liftings during the nine months ended September 30, 2021 and nine liftings during the2021. The nine months ended September 30, 2020. However,2022 includes Sasol’s interest for the total barrels lifted in the nine months ended September 30, 2021 was more than the barrels liftedentire period while during the same period in 2020, mainly due to our increased working2021, Sasol’s interest as a result ofwas included after the Sasol Acquisition partially offset by natural declines in production.acquisition date, February 25, 2021. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 98,031143,972 barrels and 36,29998,031 barrels at September 30, 2022 and 2021, and 2020, respectively.
Production expenses increased $26.9$9.4 million, or approximately 87.2%16.3%, infor the nine months ended September 30, 2021 compared2022 to the$67.1 million from $57.8 million, for same period in 2020.the prior year. The increase in expense was primarily related to higher FPSO costs, as a resultboat expense, chemical costs, personnel costs, domestic market obligation (“DMO”) costs, and other costs (collectively an increase of our increased working interest as a result of the Sasol Acquisition, increased$19.9 million), partially offset by lower workover costs, lower crude oil costs and higher marine and personnel costs. On a per barrel basis, production expense, excluding workover expense, forother costs (collectively $10.6 million). For the nine months ended September 30, 20212022 production expenses, excluding workover expense and stock compensation expense, increased to $26.75$29.10 per barrel from $21.10$26.75 per barrel for the nine months ended September 30, 20202021 primarily as a result of a natural declinehigher costs experienced in oil production and higher marine and personnel costs.2022. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $1.6 million for the nine months ended September 30, 2022 and $2.3 million and $1.2 million, respectively, in higher costs for the nine months ended September 30, 2021 related to the proactive measures taken in response to the pandemicpandemic.
FPSO demobilization costs for the nine months ended September 30, 2021 and 2020.
2022 increased to $8.9 million. These costs were incurred to retire the FPSO as we transition the block to the FSO. There were no similar expenses incurred in during the same period in 2021.
Exploration expenses was $1.3expense decreased $1.0 million, or approximately 80.6% for the nine months ended September 30, 2021 as a result of2022 to $0.3 million from $1.3 million for the same period in prior year. The decrease is due to incurring minimal amounts for seismic processing of seismic data acquired at the end of 2020. Exploration costs were not significant for the nine months ended September 30, 2022 compared to the same period in 2021 when the Company was processing the seismic data it had acquired in 2020.
Depreciation, depletion and amortization costs increased $8.8$4.9 million, or approximately 108.6%,28.9% for the nine months ended September 30, 2022 to $21.8 million from $16.9 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense is due to higher depletable costs in 2022 associated with the 2021/2022 drilling campaign.
General and administrative expenses decreased $1.7 million, or approximately 14.0% in the nine months ended September 30, 20212022 to $10.5 million compared to $12.2 million for the same period in 2020 duethe prior year. The decrease in expense was primarily related to lower corporate salary and wages, lower legal fees and higher depletable costsallocations of corporate expenses in 2022 (collectively $4.7 million) partially offset by higher audit and professional fees and other fees (collectively $3.0 million).
Bad debt expense increased by $1.2 million, or 155.9%, for the nine months ended September 30, 2022 to $2.1 million from $0.8 million for the same period in the prior year. The increase is a result of increased spending as a result of the 2021/2022 drilling campaign. The bad debt expense and related allowance account associated with the Sasol Acquisition.TVA balance has also increased as we have received no payments related to these balances in 2022.
General and administrative expenses increased $6.3 million, or approximately 105.4% in
Other operating income (expense), net for the nine months ended September 30, 2022 was not material to our results. For the nine months ended September 30, 2021, compared to the same period of 2020. The increase in expense was primarily related to an additional $4.0 million in SARs expense and an increase of $1.2 million in severance costs associated with changes in key personnel. SARs liability awards are measured at fair value. The primary driver of changes in the fair value of these awards is changes in our stock price. See Note 14 to our condensed consolidated financial statements for further discussion.
Bad debt expense was lower between the nine months ended September 30, 2021 and 2020 primarily due to bad debt expense associated with the VAT allowance.
Other operating expense, net for the nine months ended September 30, 2021 decreased by $0.4 million in expense. TheOther, net included the $0.4 million balance for the nine months ended September 30, 2021 is primarily comprised of the difference between the fair value of the contingent consideration paid to Sasol in April 2021, $5.0 million, and the fair value of the contingent consideration on the closing date of the Sasol Acquisition, $4.6 million. The balance of other operating expense for the nine months ended September 30, 2020 relates to an $0.8 million charge for the settlement of a joint venture audit.
Derivative instruments gain (loss), net is attributable to our swapsderivative instruments as discussed in Note 8 to the condensed consolidated financial statements. The $(21.1)Derivative losses increased $16.5 million to a loss of $37.5 million for the nine months ended September 30, 2021 is2022 from a loss of $21.1 million for the same period in the prior year. Derivative losses are a result of the increase in the price of Dated Brent crude oil aboveover the weighted average swapinitial strike price per barrel of our derivative instruments duringthe option over the nine months ended September 30,30,2022 and 2021, as compared to a decreaserespectively. Every quarter in the price of2021 and continuing in 2022 Dated Brent crude oil that resultedprices have increased. Since VAALCO owes the counterparty for any Dated Brent price over the initial per barrel value and we continued to place on additional hedges in a $6.6 million gain during2021 and 2022, the comparable prior year period.loss associated with the derivates has increased. Our derivative instruments currently cover a portion of our production through June 2022.March 2023.
Interest (expense) income, net decreased $0.4 million to an expense of $0.4 million for the nine months ended September 30, 2022 from expense of $0.0 million during the same period in 2021. Net interest expense for the nine months ended September 30, 2022, includes commitments fees incurred on the Facility, amortization of debt issue costs related to the Facility and interest associated with our finance leases partially offset by interest income.
Other (expense) income decreased $14.6 million to an expense of $10.5 million for the nine months ended September 30, 2022 from income of $4.1 million for the nine months ended September 30, 2021. Other (expense) income, net normally consists of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements. However, for the nine months ended September 30, 2022, Other (expense) income also included $7.6 million of transactions costs associated with the Arrangement with TransGlobe. For the nine months ended September 30, 2021, included un in Other (expense) income, net, is a bargain purchase gain of $5.5 million partially offset by $1.0 million of transaction fees associated with the Sasol Acquisition.
Income tax expense (benefit) for the nine months ended September 30, 2022 was an expense of $64.5 million. This is comprised of current tax expense of $24.9 million and $39.5 million of deferred tax expense. The deferred income tax expense for the nine months ended September 30, 2022 included a $20.2 million deferred tax benefit from the reversal of the valuation allowance. See Note 16 to the condensed consolidated financial statements for further information. Income tax expense (benefit) for the nine months ended September 30, 2021 is primarily attributable to $5.5 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee. Other, net was not significant for the nine months ended September 30, 2020.
Income tax expense (benefit) for the nine months ended September 30, 2021 was a benefit of $ (11.3) million.$11.3 million. This iswas comprised of $ (26.4)a $26.4 million of deferred tax benefit and a current tax expense of $15.1 million.million. The deferred income tax expense for the nine months ended September 30, 2021 included a $(22.3)$22.3 million deferred tax benefit from the reversal of the valuation allowance. See Note 15 to the condensed consolidated financial statements. Income tax expense for the nine months ended September 30, 2020 was $28.5 million. This is comprised
ITEM ITEM3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk
MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.
Foreign Exchange Risk
FOREIGN EXCHANGE RISK
Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the “CentralCentral African CFA Franc”,Franc, or “XAF”)XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2021,2022, we had net monetary assets of $7.3$26.3 million (XAF 4,155.517,636.4 million) (net to VAALCO) denominated in XAF. A 10% weakening of the CFA Franc relative to the U.S. dollar would have a $ (0.7)$2.4 million reduction in the value of these net assets. For the three and nine months ended September 30, 2021,2022, we had expenditures of approximately $10.7$8.8 million and $20.4$24.9 million (net to VAALCO), respectively, denominated in XAF.
COUNTERPARTY RiskRISK
We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparty. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
Commodity Price Risk
COMMODITY PRICE RISK
Our major market risk exposure continues to be the prices received for our crude oil and natural gas production. Sales prices are primarily driven by
the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue.
Sustained low crude oil and natural gas prices or a resumption of the decreases in crude oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 741731 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.7 million and $14.8 million decrease per quarter and annualized, respectively, in revenues and operating income (loss) and a $3.3 million and $13.3 million decrease per quarter and annualized in net income respectively.(loss).
As of September 30, 2021,2022, we had crude oil swaps outstanding. From time to time, we useunexpired derivative instruments asoutstanding covering 326 MBbls of production through December 2022. In October of 2022, we added derivative contracts covering 303,000 MBbls of production from January 2023 through March 2023. These instruments were intended to be an economic hedge against declines in crude oil prices; however, such instruments arethey were not designated as hedges for accounting purposes. Our derivative instruments only cover a portion of our production through June 2022. See Note 8 to our condensed consolidated financial statements for further discussion.
Interest Rate Sensitivity
Changes in market interest rates affect the amount of interest on our Facility. However as of September 30, 2022 we had no amounts drawn under the facility. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. Additionally, changes in market interest rates could impact interest costs associated with any future debt issuances.
ITEM4. CONTROLSCONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of September 30, 2021,2022, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
The internal control environment was impacted by the stay-at-home requirements for our Houston and Gabon staff which began in mid-March 2020 and was voluntary through September 1 of 2021. From September 1, 2021 through the date of this report the Company has adopted a hybrid schedule where employees are required to be in the office on certain days and allowed to work from home on certain days. While modifications were made to the manner in which controls were performed, these changes did not
There have a material effect on our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act), and there werebeen no changes in our internal control over financial reporting that occurred during the three months ended September 30, 20212022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that none of the claims and litigation we are currently involved in are material to our business.
Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 20202021 Form 10-K. Except as set forthprovided below, there have been no material changes in our risk factors from those described in our 20202021 Form 10-K.
If
Risks Related to the Completion of the Arrangement with TransGlobe
Significant demands will be placed on the Combined Company as a result of the recent completion of the Arrangement.
As a result of the pursuit and completion of the Arrangement, significant demands have and will continue to be placed on the managerial, operational and financial personnel and systems of the Combined Company. We cannot provide any assurance that management of VAALCO and the operations teams of the Combined Company will be adequate to support the expansion of operations and associated increased costs and complexity following and resulting from the recent consummation of the Arrangement. The future operating results of the Combined Company will be affected by the ability of its officers and key employees to manage changing business conditions, integrate the acquisition of TransGlobe and implement a new business strategy.
We may not realize the anticipated benefits of the Arrangement and the integration of TransGlobe may not occur as planned.
The Arrangement was agreed to with the expectation that its completion will result in accretive reserves and expected production amounts as well as enhanced growth capital markets opportunities for the Combined Company. These anticipated benefits will depend in part on whether TransGlobe’s and VAALCO’s operations can be integrated in an efficient and effective manner. A significant number of operational and strategic decisions and certain staffing decisions with respect to integration of the two companies have not yet been made. These decisions and the integration of the two companies will present challenges to management, including the integration of systems and personnel of the two companies which may be geographically separated, anticipated and unanticipated liabilities, unanticipated costs (including substantial capital expenditures required by the integration) and the loss of key employees. In particular, following a transition period of up to six months following consummation of the Arrangement, we areexpect the departure of TransGlobe’s former President and Chief Executive Officer, Vice President, Finance, Chief Financial Officer and Corporate Secretary and Vice President and Chief Operating Officer. These departures may result in a loss of institutional knowledge concerning TransGlobe’s operations and could delay the achievement of the Combined Company’s strategic objectives. In addition, there may be potential unknown liabilities of TransGlobe that may prevent the Combined Company from fully realizing the anticipated benefits of the Arrangement.
The performance of the Combined Company’s operations now that the Arrangement has been completed could be adversely affected if, among other things, the Combined Company is not able to timely implementachieve the transitionanticipated benefits expected to be realized in entering the Arrangement or retain key employees to assist in the integration and operation of TransGlobe and VAALCO. In particular, the Combined Company may not be able to realize the anticipated strategic benefits and synergies from the Arrangement. We believe that the combination of the companies will provide a number of operational and financial benefits. However, achieving these goals assumes, among other things, the realization of the targeted cost synergies expected from the Arrangement. The consummation of the Arrangement may pose special risks, including one-time write-offs, restructuring charges and unanticipated costs. In addition, the integration process could result in diversion of the attention of management and disruption of existing relationships with suppliers, employees, customers and other constituencies of each company. Although we and our advisors have conducted due diligence on the operations of TransGlobe, there can be no guarantee that we are aware of any and all liabilities of TransGlobe.
In addition, our management has assumed that we will be able to elect to treat the Arrangement as an asset acquisition under Section 338(g) of the Internal Revenue Code of 1986, as amended (the “Code”). This election may be unavailable if existing TransGlobe shareholders own shares of VAALCO common stock in an amount that prevents the Arrangement from being a “qualified stock purchase” (within the meaning of Section 338(d)(3) of the Code).
A determination of the common ownership of VAALCO and TransGlobe is not possible until the closing of the arrangement and may still be subject to uncertainty following the closing If an election under Section 338(g) of the Code is unavailable, the integration of TransGlobe may give rise to additional tax costs and the actual combined performance of VAALCO and TransGlobe following the arrangement may differ materially from the assumptions of VAALCO’s management. As a result of these and other factors, it is possible that certain benefits expected from the combination of TransGlobe and VAALCO may not be realized.
The Combined Company may not generate sufficient cash to satisfy TransGlobe’s payment obligations under the Merged Concession Agreement or be able to collect some or all of TransGlobe’s receivables from the EGPC, which could negatively affect the Combined Company’s operating results and financial condition.
On January 19, 2022, subsidiaries of TransGlobe executed an agreement with the EGPC (the “Merged Concession Agreement”) to update and merge TransGlobe’s three Egyptian concessions in West Bakr, West Gharib and NW Gharib (the “Merged Concession”). The Merged Concession Agreement was signed by its parties on January 19, 2022 with an effective date of February 1, 2020 (the “Merged Concession Effective Date”). As part of the conditions precedent to the FSO unit before the expirationsigning of the FPSO contractMerged Concession Agreement by the Minister of Petroleum & Mineral Resources on behalf of the Egyptian Government, TransGlobe remitted the initial modernization payment of $15.0 million and signature bonus of $1.0 million. In accordance with the Merged Concession Agreement, TransGlobe made another modernization payment to the EGPC in Septemberthe amount of $10.0 million on February 1, 2022. The modernization payments under the Merged Concession Agreement total $65.0 million and are payable over six years from the Merged Concession Effective Date. Under the agreement, TransGlobe will be required to pay an additional $10.0 million on February 1st for each of the next four years. In addition, TransGlobe has committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (total $150.0 million). TransGlobe’s ability to make scheduled payments arising from the Merged Concession Agreement will depend on its financial condition and operating performance, which would be subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond its control. TransGlobe may be unable to maintain a level of cash flow sufficient to permit it to satisfy the payment obligations under the Merged Concession Agreement. If TransGlobe is unable to satisfy its obligations, it is possible that the EGPC could seek to terminate the Merged Concession Agreement, which would negatively affect the combined company’s operating results and financial condition.
In addition, upon execution of the Merged Concession Agreement, there was a Merged Concession Effective Date adjustment of funds owed to TransGlobe for the difference between the commercial terms in the Concession Agreement and the Merged Concession Agreement applicable to the Eastern Desert production from the Merged Concession Effective Date. The quantum of this adjustment is currently being finalized with the EGPC and could result in a range of outcomes based on the final price per barrel negotiated. TransGlobe has recognized a receivable of $67.5 million as of June 30, 2022, which represents the amount expected to be received from the EGPC based on historical realized prices. If the EGPC’s financial position becomes impaired or it disputes or if the EGPC refuses to pay some or all of the said amount, TransGlobe’s ability to fully collect such receivable from the EGPC could be impaired, which could negatively affect the combined company’s operating results and financial condition.
Inflation could adversely impact the Combined Company’s ability to control its costs, including its operating expenses and capital costs.
Although inflation has been relatively low in recent years, it rose significantly in the second half of 2021 and the first nine months of 2022. In addition, global and industry-wide supply chain disruptions have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase, as well as a scarcity of certain products and raw materials. To the extent elevated inflation remains, the combined company may experience further cost increases for its operations, including oilfield services and equipment as increasing prices of oil, natural gas and natural gas liquids increased drilling activity in its areas of operations, as well as increased labor costs. An increase in the prices of oil, natural gas and natural gas liquids may cause the costs of materials and services we use to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, could negatively impact our business, financial condition and results of operation.
TransGlobe’s public filings are subject to Canadian disclosure standards, which differ from SEC disclosure requirements.
VAALCO’s reserve estimates have been prepared in accordance with United States Financial Accounting Standards Board’s (“FASB”) ASC Topic 932 – Extractive Activities – Oil and Natural Gas under U.S. GAAP and subpart 1200 of Regulation S-K promulgated by the SEC (the “U.S. Standards”). VAALCO has not been involved in the preparation of TransGlobe’s historical oil and natural gas reserves estimates. TransGlobe’s historical oil and natural gas reserves estimates were prepared in accordance with the standards set forth in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook, which differ from the requirements of United States securities laws. In addition to being a reporting issuer in all provinces of Canada, TransGlobe is a registrant with the SEC but is permitted to present disclosure of its reserves information in accordance with the standards set out in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook.
Estimates of reserves and future net revenue made in accordance with NI 51-101 will differ from corresponding U.S. GAAP standardized measure prepared in accordance with U.S. Standards and those differences may be material. For example, the U.S. standards require United States oil and gas reporting companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and production due to others but permits the optional disclosure of probable and possible reserves in accordance with SEC’s definitions. Additionally, the COGE Handbook and NI 51-101 require disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas the U.S. Standards require that reserves and related future net revenue be estimated using average prices for the previous 12 months and that the standardized measure reflect discounted future net income taxes related to VAALCO’s operations. In addition, the COGE Handbook and NI 51-101 permit the presentation of reserves estimates on a “company gross” basis, representing TransGlobe’s working interest share before deduction of royalties, whereas the U.S. Standards require the presentation of net reserve estimates after the deduction of royalties and similar payments. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGE Handbook, and those applicable under the U.S. Standards. NI 51-101 requires that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves. Finally, the SEC prohibits disclosure of oil and gas resources in SEC filings, including contingent resources, whereas Canadian securities regulatory authorities allow disclosure of oil and gas resources. Resources are different than, and should not be construed as, reserves. The foregoing is not an exhaustive summary of Canadian or U.S. reserves reporting requirements.
The Combined Company faces political risks in new jurisdictions.
TransGlobe’s principal operations, development and exploration activities and significant investments are held in Canada and Egypt, some of which may be considered to have an increased degree of political and sovereign risk. Any material adverse changes in government policies or legislation of such countries or any other country that TransGlobe has economic interests in that affect oil and gas exploration activities may affect the viability and profitability of the Combined Company.
While the governments in Canada, Egypt and other countries in which TransGlobe has oil and gas operations or development or exploration projects have historically supported the development of natural resources by foreign companies, there is no assurance that such governments will not in the future adopt different regulations, policies or interpretations with respect to, but not limited to, foreign ownership of oil and gas resources, royalty rates, taxation, rates of exchange, environmental protection, labor relations, repatriation of income or return of capital, restrictions on production or processing, price controls, export controls, currency remittance, or the obligations of TransGlobe under its respective oil and gas laws, code or standards. The possibility that such governments may adopt substantially different policies or interpretations, which might extend to the expropriation of assets, may have a material adverse effect on the combined company following the arrangement. Political risk also includes the possibility of terrorism, civil or labor disturbances and political instability. No assurance can be given that applicable governments will not revoke or significantly alter the conditions of the applicable oil and gas authorizations nor can assurance be given that such oil and gas authorizations will not be challenged or impugned by third parties. The effect of any of these factors may have a material adverse effect on the Combined Company’s results of operations couldand financial condition.
Upon consummation of the arrangement, we became a reporting issuer in Canada and are therefore subject to certain Canadian disclosure requirements.
Upon consummation of the arrangement, we became a reporting issuer in each of the provinces of Canada and is subject to Canadian continuous disclosure and other reporting obligations under applicable Canadian securities laws. Most Canadian continuous disclosure requirements are codified in National Instrument 51-102 – Continuous Disclosure Obligations (“NI 51-102”) of the Canadian Securities Administrators. The application of these requirements to VAALCO is modified by various rules providing exemptions for non-Canadian issuers in certain circumstances, including National Instrument 71-101 – The Multijurisdictional Disclosure System (“NI 71-101”) and National Instrument 71-102 – Continuous Disclosure and Other Exemptions Relating to Foreign Issuers (“NI 71-102”). NI 51-102 generally requires that issuers file audited annual financial statements and unaudited interim financial statements meeting certain requirements, management’s discussion and analysis relating to its annual and interim financial statements, an annual information form, material change reports and other disclosure items at prescribed times and/or upon the occurrence of certain specified events. We will be materially adversely affected.
As an offshore producer,able to satisfy most of its Canadian reporting obligations under Canadian securities laws by filing certain of its U.S. disclosure documents in accordance with the exemptions codified in NI 71-101 and NI 71-102 on the System for Electronic Document Analysis and Retrieval at www.sedar.com. Nonetheless, we dependwill be required to prepare and disclose our reserves information in accordance with the COGE Handbook and NI 51-101, and such disclosure standards differ from the SEC’s applicable disclosure requirements. See “—TransGlobe’s public filings are subjectto Canadian disclosure standards, which differ from SEC disclosure requirements.” These additional reporting obligations will cause us to incur increased compliance costs and place increased demands on our FPSO to store all of the crude oil we produce prior to sale tomanagement, administrative, operational and accounting resources and on our customers. Our current FPSO contract expires in September 2022. On August 31, 2021, we entered intoaudit committee. As a Bareboat Contract and Operating Agreement for a Floating Storage and Offloading (“FSO”) unit at the Etame Marin field offshore Gabon for up to eight years with additional option periods available upon the expiration of the current FPSO contract in September 2022. The transition to the FSO unit will require a significant lead time and may require a capital investment due to the specialized nature of such vessels. To become operational, significant engineering studies, platform modifications, mooring and pipeline surveys as well as installation must be completed. If we are not able to timely implement the transition to the FSO unit as our alternative method of storing the crude oil we produce, thengeneral matter, we will not be able to sell crude oilcease to be a Canadian reporting issuer unless and until residents of Canada do not: (i) directly or indirectly beneficially own more than 2% of each class or series of outstanding securities (including debt securities) of VAALCO worldwide; and (ii) directly or indirectly comprise more than 2% of the total number of securityholders of VAALCO worldwide.
Upon consummation of the arrangement, VAALCO became subject to the Canadian take-over bid regime pursuant to applicable Canadian securities laws.
Upon consummation of the arrangement, VAALCO became subject to the Canadian take-over bid regime pursuant to applicable Canadian securities laws. In general, a take-over bid is an offer to acquire voting or equity securities of a class made to persons in a Canadian jurisdiction where the securities subject to the bid, together with securities beneficially owned, or over which control or direction is exercised, by a bidder, its affiliates and joint actors, constitute 20% or more of the outstanding securities of that class of securities. Subject to the availability of an exemption, take-over bids in Canada are subject to prescribed rules that govern the conduct of a bid by requiring a bidder to comply with detailed disclosure obligations and procedural requirements. Among other things, a take-over bid must be made to all holders of the class of voting or equity securities being purchased; a bid is required to remain open for a minimum of 105 days subject to certain limited exceptions; a bid is subject to a mandatory, non-waivable minimum tender requirement of more than 50% of the outstanding securities of the class that are subject to the bid, excluding securities beneficially owned, or over which control or direction is exercised, by a bidder, its affiliates and joint actors; and following the satisfaction of the minimum tender requirement and the satisfaction or waiver of all other terms and conditions, a bid is required to be extended for at least an additional 10-day period. There are a limited number of exemptions from the formal take-over bid requirements. In general, certain of these exemptions include the following: (i) the normal course purchase exemption permits the holder of more than 20% of a class of equity or voting securities to purchase up to an additional 5% of the outstanding securities in a 12-month period (when aggregated with all other purchases in that period), provided there must be a published market and the purchaser must pay not more than the “market price” of the securities (as defined) plus reasonable brokerage fees or commissions actually paid; (ii) the private agreement exemption exempts private agreement purchases that result in the purchaser exceeding the 20% take-over bid threshold, provided the agreement must be made with not more than five sellers and the sellers may not receive more than 115% of the “market price” of the securities (as defined); and (iii) the foreign take-over bid exemption exempts a bid from the formal take-over bid requirements if, among other things, less than 10% of the outstanding securities of the class are held by Canadian residents and the published market on which the greatest volume of trading in securities of the class occurred in the 12 months prior to the bid was not in Canada.
Increased exposure to foreign exchange fluctuations and capital controls may adversely affect the combined company’s earnings and the value of some of the combined company’s assets.
Our reporting currency is the U.S. dollar and the majority of our earnings and cash flows are denominated in U.S. dollars. The operations of TransGlobe are also reported in U.S. dollars, but TransGlobe conducts some of its business in currencies other than the U.S. dollar and, as a result, the Combined Company’s consolidated earnings and cash flows may be impacted by movements in the exchange rates to a greater extent than prior to the Arrangement. In particular, any change in the value of the currencies of the Canadian Dollar or the Egyptian Pound versus the U.S. dollar could negatively impact the Combined Company’s earnings, and could negatively impact the Combined Company’s ability to realize all of the anticipated benefits of the Arrangement.
In addition, from time to time, emerging market countries such as those in which the Combined Company will operate adopt measures to restrict the availability of the local currency or the repatriation of capital across borders. These measures are imposed by governments or central banks, in some cases during times of economic instability, to prevent the removal of capital or the sudden devaluation of local currencies or to maintain in-country foreign currency reserves. In addition, many emerging markets countries require consents or reporting processes before local currency earnings can be converted into U.S. dollars or other currencies and/or such earnings can be repatriated or otherwise transferred outside of the operating jurisdiction. These measures may have a number of negative effects on the Combined Company, reduction of the immediately available capital that the Combined Company could otherwise deploy for investment opportunities or the payment of expenses. In addition, measures that restrict the availability of the local currency or impose a requirement to operate in the local currency may create other practical difficulties for the Combined Company.
The combined company will face new legislation and tax risks in certain TransGlobe operating jurisdictions.
TransGlobe has operations and conducts business in multiple jurisdictions in which we do not currently operate or conduct business, which may increase our susceptibility to sudden tax changes. Taxation laws in these jurisdictions are complex, subject to varying interpretations and applications by the relevant tax authorities and subject to changes and revisions in the ordinary course, which could result in an increase in TransGlobe’s taxes, or other governmental charges, duties or impositions, or an unreasonable delay in the refund of certain taxes owing to TransGlobe. No assurance can be given that new tax laws, rules or regulations will not be enacted or that existing tax laws will not be changed, interpreted or applied in a manner that could result in the Combined Company’s profits being subject to additional taxation, result in the combined company not recovering certain taxes on a timely basis or at all, or that could otherwise have a material adverse effect on the Combined Company.
The declaration, payment and amounts of dividends, if any, distributed to our customers. Consequently,stockholders following competition of the Arrangement will be uncertain.
Although each of VAALCO and TransGlobe has paid cash dividends on its respective shares of common stock in the past, our Board of Directors may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends will remain in the discretion of the full Board of Directors (as reconstituted following the Arrangement). Any dividend payment amounts will be determined by the Board of Directors, and it is possible that the Board of Directors may increase or decrease the amount of dividends paid in the future, or determine not to declare dividends in the future, at any time and for any reason. We expect that any such decisions will depend on the combined business’s financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that the Board of Directors deems relevant, including, but not limited to:
● | whether we have enough cash to pay such dividends due to its cash requirements, capital spending plans, cash flows or financial position; |
● | our desire to maintain or improve the credit ratings on any future debt; and |
● | applicable restrictions under Delaware law. |
Stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared.
Risks Related to the Facility Agreement
A significant level of indebtedness incurred under the Facility may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities in the future. In addition, the covenants in the Facility impose restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of any future outstanding indebtedness under the Facility.
The Facility Agreement governing our Facility with Glencore contains certain affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments. Restrictions contained in the Facility governing any future indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Any future indebtedness under the Facility and other financial obligations and restrictions could have financial consequences. For example, they could:
● | impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes; |
● | increase our vulnerability to general adverse economic and industry conditions; |
● | require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements; |
● | limit our flexibility in planning for, or reacting to, changes in our business and industry; and |
● | place us at a competitive disadvantage to those who have proportionately less debt. |
Our ability to comply with these covenants could be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A prolonged period of oil and gas prices at declined levels could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. A breach of any of these provisions could result in a default under the Facility, which could allow all amounts outstanding thereunder to be declared immediately due and payable. In the event of such acceleration, we cannot assure that we would be requiredable to shut in production until such time that we could offload the oil, andrepay our results of operations woulddebt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be materially adversely affected.
on terms acceptable to us. We may not enter into definitive agreementsalso be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under the Facility.
If we experience in the future a continued period of low commodity prices, our ability to comply with the consortiumFacility’s debt covenants may be impacted.
Under the Facility Agreement, we are subject to explorecertain debt covenants, including that (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and exploit new properties,(ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. We were in compliance with covenants under the Facility through September 30, 2022; however, commodity prices have been extremely volatile in recent history and a protracted future decline in commodity prices could cause us to not be in compliance with certain financial covenants under the Facility in future periods. A breach of the covenants under the Facility would cause a default, potentially resulting in acceleration of all amounts outstanding under the Facility. Certain payment defaults or acceleration under the Facility could cause a cross-default or cross-acceleration of other future outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other future debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not be in a positionhave sufficient liquidity to control the timingrepay all of development efforts, the associated costs or the rate of production of the reserves operated by the consortium or from any non-operated properties we have an interest in.our outstanding indebtedness.
On October 11, 2021 we announced our entry into a consortium with BW Energy and Panoro Energy and thatThe borrowing base under the consortium has been provisionally awarded two blocks, G12-13 and H12-13, in the 12th Offshore Licensing Round in Gabon. The award is subjectFacility may be reduced pursuant to concluding the terms of the production sharing contracts withFacility Agreement, which may limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.
In the Gabonese government. BW Energy will befuture we may depend on the operator withFacility for a 37.5% working interestportion of our capital needs. The initial borrowing base under the Facility is $50.0 million and weis redetermined on March 31 and Panoro Energy will have a 37.5% working interest and 25% working interest, respectively, as non-operating joint owners. The joint owners inSeptember 30 of each year. Borrowings under the consortium intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. Our obligations within the consortiumFacility are subjectlimited to a numberborrowing base amount calculated pursuant to the Facility Agreement based on the Company’s proved producing reserves and a portion of conditions, including the negotiationCompany's proved undeveloped reserves. The Lenders will redetermine the borrowing base based on forecasts of cashflow and executiondebt service projections with respect to the borrowing base assets, which may result in a reduction of production sharing contracts with the Gabonese government, as wellborrowing base.
In the entry into joint operating agreements with our joint interest owners. There is no assurance that we will be able to agree to terms on definitive production sharing contracts with the Gabonese government nor joint operating agreements with the joint owners in the consortium. If we are unable to negotiate and enter into definitive agreements with each party,future, we may not be able to explore, develop and exploit new properties, andaccess adequate funding under the Facility as a result of (i) a decrease in our resultsborrowing base due to the outcome of operations could be materially adversely affected.
With respect to crude oil and natural gas projects that we do not operatea subsequent borrowing base redetermination, or may not operate in(ii) an unwillingness or inability on the future, including properties operated by the consortium, we have or will have limited ability to exercise influence over the operationspart of the non-operated properties andLenders to meet their associated costs, including limited control overfunding obligations. As a result, we may be unable to obtain adequate funding under the maintenance of safety and environmental standards. Our dependenceFacility. If funding is not available when needed, or is available only on the operator and other non-operating joint owners, andunfavorable terms, it could adversely affect our limited ability to influence operations and associated costs of properties operated by others, could prevent the realization ofdevelopment plans as currently anticipated, results in drilling or acquisition activities. In addition, the operator of these properties may act in ways that are not in our best interest. The success and timing of development and exploitation activities on properties operated by others, including those operated by the consortium, depends upon a number of factors that could be largely outside of our control, including:
the timing and amount of capital expenditures;
the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;
the operator’s expertise, financial resources and willingness to initiate exploration or development projects;
approval of other participants in drilling wells;
risk of other a non-operator’s failure to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;
selection of technology;
delays in the pace of exploratory drilling or development;
the rate of production of the reserves; and/or
the operator’s desire to drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.
The occurrence of any of the foregoing events could have a material adverse effect on our anticipated explorationproduction, revenues and development activities.results of operations.
Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or
Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business plans,activities that may be in our best interests.
The Facility Agreement contains a number of significant affirmative and negative covenants that, among other things, restrict our ability to:
● | dispose of assets; |
● | enter into guarantees or indemnities; |
● | incur indebtedness; |
● | enter into certain material contracts; |
● | merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries; or |
● | pursue other corporate activities. |
Also, the Facility Agreement requires us to maintain compliance with certain financial covenants. Our ability to comply with these financial covenants may be affected by events beyond our control, and, as a result, in significant expenditures or reduce demand for our product.
Climate changes continueswe may be unable to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce the emissions of GHG emissions.meet these financial covenants. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. These programs mayfinancial covenants could limit our ability to produce crudeobtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the Facility Agreement. A breach of any of these covenants or our inability to comply with the required financial covenants could result in an event of default under the Facility Agreement. When oil andand/or natural gas limitprices decline for an extended period of time or when our liquidity is constrained, our ability to explorecomply with these covenants becomes more difficult. Although we are currently in new areas,compliance with these covenants, if in the future oil and gas prices decline for an extended period of time, we may default on one or more of these covenants. Such a default, if not cured or waived, may make it more expensiveallow the Lenders to produce.accelerate the related indebtedness and could result in acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies.
An event of default under the Facility Agreement would permit the Lenders to cancel all commitments to extend further credit under the Facility. Furthermore, if we were unable to repay the amounts due and payable under the Facility Agreement, the Lenders could proceed against the collateral granted to them to secure that indebtedness. In addition, these programs may reduce demand for our product either by incentivizing or mandating the use of other alternative energy sources, by prohibitingevent that the useLenders accelerate the repayment of our product,borrowings under the Facility, we and our subsidiaries may not have sufficient assets to repay that indebtedness. As a result of these restrictions, we may be:
● | limited in how we conduct our business; |
● | unable to raise additional debt or equity financing during general economic, business or industry downturns; or |
● | unable to compete effectively or to take advantage of new business opportunities. |
Risks Related to Our Industry
We are currently operating in a period of economic uncertainty and capital markets disruption, which has been significantly impacted by requiring equipment using our productgeopolitical instability due to shiftthe ongoing military conflict between Russia and Ukraine. Our business may be materially adversely affected by any negative impact on the global economy and capital markets resulting from the conflict in Ukraine or any other geopolitical tensions.
U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict between Russia and Ukraine. On February 24, 2022, a full-scale military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine could lead to alternative energy sources, or by directly increasing the cost of fossil fuels to consumers.
An increased societalmarket disruptions, including significant volatility in commodity prices, credit and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our product.
An increased expectation that companies address environmental (including climate change), social and governance (“ESG”) matters may have a myriad of impacts to our business. Some investors and lenders are factoring these issues into investment and financing
decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings,capital markets, as well as recent activism around fossil fuels, may dissuade investors or lenders from ussupply chain interruptions. We are continuing to toward other industries, which could negatively impact our stock price or our access to capital.
Moreover, while we havemonitor the situation in Ukraine and may continue to createglobally and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
In addition, ESG and climate chance issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for our products. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for our product.
Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate theirassessing its potential impact on our business.
Additionally, Russia’s prior annexation of Crimea, recent recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military interventions in Ukraine have led to sanctions and other penalties being levied by the United States, European Union and other countries against Russia, Belarus, others, including an agreement to remove certain Russian financial condition, resultsinstitutions from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system, expansive ban on imports and exports of operationsproducts to and abilityfrom Russia and ban on exportation of U.S denominated banknotes to compete. However, any long-term material adverse effect onRussia or persons located there. Additional potential sanctions and penalties have also been proposed and/or threatened. Russian military actions and the resulting sanctions could adversely affect the global economy and financial markets and lead to increased volatility in oil and gas industry may adversely affect our financial condition, resultsprices or create supply chain interruptions. The extent and duration of operationsthe military action, sanctions and resulting market disruptions are impossible to predict, but could be substantial.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sale of Equity Securities
There were no sales of unregistered securities during the quarter ended September 30, 2022 that were not previously reported on a Current Report on Form 8-K.
Issuer Repurchases of Common Stock
On November 1, 2022, we announced that VAALCO’s newly-expanded board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with the Company’s business combination with TransGlobe. The board of directors also directed management to implement the Plan to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flows.flow from operations.
ITEM 6. EXHIBITS
(a) Exhibits
104
Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).
(a) Filed herewith
(b) Furnished herewith
* Management contract or compensatory plan or arrangement.
** Information in this exhibit (indicated by asterisks) is confidential and has been omitted pursuant to Item 601(b)(10) of Regulation S-K. Additionally, exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted exhibit or schedule will be furnished supplementally to the SEC or its staff upon request.
64
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VAALCO ENERGY, INC.
(Registrant)
By | : | /s/ Ronald Bain | |
Ronald Bain | |||
| |||
Chief Financial Officer (Principal Financial Officer) |
Dated: November 3, 20218, 2022