Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2021 | Oct. 26, 2021 | |
Cover [Abstract] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2021 | |
Document Transition Report | false | |
Entity File Number | 1-32167 | |
Entity Registrant Name | VAALCO Energy, Inc. | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 76-0274813 | |
Entity Address, Address Line One | 9800 Richmond Avenue | |
Entity Address, Address Line Two | Suite 700 | |
Entity Address, City or Town | Houston | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77042 | |
City Area Code | 713 | |
Local Phone Number | 623-0801 | |
Title of 12(b) Security | Common Stock | |
Trading Symbol | EGY | |
Security Exchange Name | NYSE | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | true | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 58,611,072 | |
Current Fiscal Year End Date | --12-31 | |
Entity Central Index Key | 0000894627 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q3 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Current assets: | ||
Cash and cash equivalents | $ 52,839 | $ 47,853 |
Restricted cash | 81 | 86 |
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 |
Crude oil inventory | 2,556 | 3,906 |
Prepayments and other | 5,416 | 4,215 |
Total current assets | 64,084 | 63,978 |
Crude oil and natural gas properties, equipment and other - successful efforts method, net | 74,102 | 37,036 |
Other noncurrent assets: | ||
Restricted cash | 1,752 | 925 |
Value added tax and other receivables, net of allowance of $5.8 million and $2.3 million, respectively | 5,670 | 4,271 |
Right of use operating lease assets | 12,984 | 22,569 |
Deferred tax assets | 24,211 | |
Abandonment funding | 22,281 | 12,453 |
Other long-term assets | 1,176 | |
Total assets | 206,260 | 141,232 |
Current liabilities: | ||
Accounts payable | 8,433 | 16,690 |
Accounts with joint venture owners | 2,325 | 4,945 |
Accrued liabilities and other | 39,857 | 17,184 |
Operating lease liabilities - current portion | 12,671 | 12,890 |
Foreign income taxes payable | 860 | |
Current liabilities - discontinued operations | 7 | 7 |
Total current liabilities | 63,293 | 52,576 |
Asset retirement obligations | 33,077 | 17,334 |
Operating lease liabilities - net of current portion | 312 | 9,671 |
Other long-term liabilities | 193 | |
Total liabilities | 96,682 | 79,774 |
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 |
Additional paid-in capital | 76,346 | 74,437 |
Less treasury stock, 10,939,323 and 10,366,376 shares, respectively, at cost | (43,847) | (42,421) |
Retained earnings | 70,126 | 22,652 |
Total shareholders' equity | 109,578 | 61,458 |
Total liabilities and shareholders' equity | $ 206,260 | $ 141,232 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2021 | Dec. 31, 2020 |
Condensed Consolidated Balance Sheets [Abstract] | ||
Allowance for accounts with joint venture owners | $ 0 | $ 0 |
Allowance for value added tax and other receivables | $ 5.8 | $ 2.3 |
Preferred stock, par value | $ 25 | $ 25 |
Preferred stock, shares authorized | 500,000 | 500,000 |
Preferred stock, shares issued | 0 | 0 |
Common stock, par value | $ 0.10 | $ 0.10 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 69,528,100 | 67,897,530 |
Common stock, shares outstanding | 58,588,777 | 57,531,154 |
Treasury stock, shares | 10,939,323 | 10,366,376 |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Operations - USD ($) shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Revenues: | ||||
Crude oil and natural gas sales | $ 55,899,000 | $ 18,256,000 | $ 142,696,000 | $ 54,619,000 |
Operating costs and expenses: | ||||
Production expense | 25,208,000 | 8,984,000 | 57,760,000 | 30,859,000 |
Exploration expense | 479,000 | 16,000 | 1,286,000 | 16,000 |
Depreciation, depletion and amortization | 6,970,000 | 2,212,000 | 16,928,000 | 8,116,000 |
Impairment of proved crude oil and natural gas properties | 0 | 0 | 0 | 30,625,000 |
General and administrative expense | 2,940,000 | 2,178,000 | 12,221,000 | 5,951,000 |
Bad debt expense and other | 318,000 | 151,000 | 814,000 | 1,140,000 |
Total operating costs and expenses | 35,915,000 | 13,541,000 | 89,009,000 | 76,707,000 |
Other operating income (expense), net | 46,000 | (37,000) | (440,000) | (883,000) |
Operating income (loss) | 20,030,000 | 4,678,000 | 53,247,000 | (22,971,000) |
Other income (expense): | ||||
Derivative instruments gain (loss), net | (5,147,000) | (21,070,000) | 6,583,000 | |
Interest income, net | 3,000 | 23,000 | 9,000 | 150,000 |
Other, net | (328,000) | 147,000 | 4,088,000 | 163,000 |
Total other income (expense), net | (5,472,000) | 170,000 | (16,973,000) | 6,896,000 |
Income (loss) from continuing operations before income taxes | 14,558,000 | 4,848,000 | 36,274,000 | (16,075,000) |
Income tax expense (benefit) | (17,183,000) | (2,759,000) | (11,272,000) | 28,470,000 |
Income (loss) from continuing operations | 31,741,000 | 7,607,000 | 47,546,000 | (44,545,000) |
Income (loss) from discontinued operations, net of tax | (20,000) | 11,000 | (72,000) | (41,000) |
Net income (loss) | $ 31,721,000 | $ 7,618,000 | $ 47,474,000 | $ (44,586,000) |
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 | 0 | 0 | 0 |
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 | 0 | 0 | 0 |
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 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements Of Shareholders' Equity - USD ($) $ in Thousands | Common Stock [Member] | Additional Paid-In Capital [Member] | Treasury Stock [Member] | Retained Earnings [Member] | Total |
Balance at Dec. 31, 2019 | $ 6,767 | $ 73,549 | $ (41,429) | $ 70,833 | $ 109,720 |
Balance, Shares at Dec. 31, 2019 | 67,674,000 | ||||
Balance, Treasury Shares at Dec. 31, 2019 | (9,649,000) | ||||
Shares issued - stock-based compensation | $ 13 | (13) | |||
Shares issued - stock-based compensation, Shares | 125,000 | ||||
Stock-based compensation expense | 145 | 145 | |||
Treasury stock | $ (652) | (652) | |||
Treasury stock, Shares | (517,000) | ||||
Net income (loss) | (52,800) | (52,800) | |||
Balance at Mar. 31, 2020 | $ 6,780 | 73,681 | $ (42,081) | 18,033 | 56,413 |
Balance, Shares at Mar. 31, 2020 | 67,799,000 | ||||
Balance, Treasury Shares at Mar. 31, 2020 | (10,166,000) | ||||
Balance at Dec. 31, 2019 | $ 6,767 | 73,549 | $ (41,429) | 70,833 | 109,720 |
Balance, Shares at Dec. 31, 2019 | 67,674,000 | ||||
Balance, Treasury Shares at Dec. 31, 2019 | (9,649,000) | ||||
Net income (loss) | (44,586) | ||||
Balance at Sep. 30, 2020 | $ 6,782 | 74,061 | $ (42,419) | 26,247 | 64,671 |
Balance, Shares at Sep. 30, 2020 | 67,819,000 | ||||
Balance, Treasury Shares at Sep. 30, 2020 | (10,363,000) | ||||
Balance at Mar. 31, 2020 | $ 6,780 | 73,681 | $ (42,081) | 18,033 | 56,413 |
Balance, Shares at Mar. 31, 2020 | 67,799,000 | ||||
Balance, Treasury Shares at Mar. 31, 2020 | (10,166,000) | ||||
Shares issued - stock-based compensation | $ 2 | (2) | |||
Shares issued - stock-based compensation, Shares | 20,000 | ||||
Stock-based compensation expense | 60 | 60 | |||
Treasury stock | $ (338) | (338) | |||
Treasury stock, Shares | (197,000) | ||||
Net income (loss) | 596 | 596 | |||
Balance at Jun. 30, 2020 | $ 6,782 | 73,739 | $ (42,419) | 18,629 | 56,731 |
Balance, Shares at Jun. 30, 2020 | 67,819,000 | ||||
Balance, Treasury Shares at Jun. 30, 2020 | (10,363,000) | ||||
Shares issued - stock-based compensation | |||||
Stock-based compensation expense | 322 | 322 | |||
Treasury stock | |||||
Net income (loss) | 7,618 | 7,618 | |||
Balance at Sep. 30, 2020 | $ 6,782 | 74,061 | $ (42,419) | 26,247 | 64,671 |
Balance, Shares at Sep. 30, 2020 | 67,819,000 | ||||
Balance, Treasury Shares at Sep. 30, 2020 | (10,363,000) | ||||
Balance at Dec. 31, 2020 | $ 6,790 | 74,437 | $ (42,421) | 22,652 | $ 61,458 |
Balance, Shares at Dec. 31, 2020 | 67,897,000 | ||||
Balance, Treasury Shares at Dec. 31, 2020 | (10,366,000) | (10,366,376) | |||
Shares issued - stock-based compensation | $ 43 | 304 | $ 347 | ||
Shares issued - stock-based compensation, Shares | 431,000 | (155,000) | |||
Stock-based compensation expense | 323 | 323 | |||
Treasury stock | $ (403) | (403) | |||
Net income (loss) | 9,869 | 9,869 | |||
Balance at Mar. 31, 2021 | $ 6,833 | 75,064 | $ (42,824) | 32,521 | 71,594 |
Balance, Shares at Mar. 31, 2021 | 68,328,000 | ||||
Balance, Treasury Shares at Mar. 31, 2021 | (10,521,000) | ||||
Balance at Dec. 31, 2020 | $ 6,790 | 74,437 | $ (42,421) | 22,652 | $ 61,458 |
Balance, Shares at Dec. 31, 2020 | 67,897,000 | ||||
Balance, Treasury Shares at Dec. 31, 2020 | (10,366,000) | (10,366,376) | |||
Net income (loss) | $ 47,474 | ||||
Balance at Sep. 30, 2021 | $ 6,953 | 76,346 | $ (43,847) | 70,126 | $ 109,578 |
Balance, Shares at Sep. 30, 2021 | 69,528,000 | ||||
Balance, Treasury Shares at Sep. 30, 2021 | (10,939,000) | (10,939,323) | |||
Balance at Mar. 31, 2021 | $ 6,833 | 75,064 | $ (42,824) | 32,521 | $ 71,594 |
Balance, Shares at Mar. 31, 2021 | 68,328,000 | ||||
Balance, Treasury Shares at Mar. 31, 2021 | (10,521,000) | ||||
Shares issued - stock-based compensation | $ 109 | 597 | $ (314) | 706 | |
Shares issued - stock-based compensation, Shares | 1,092,000 | ||||
Stock-based compensation expense | 117 | 117 | |||
Treasury stock | (765) | (765) | |||
Net income (loss) | 5,884 | 5,884 | |||
Balance at Jun. 30, 2021 | $ 6,942 | 75,778 | $ (43,589) | 38,405 | 77,536 |
Balance, Shares at Jun. 30, 2021 | 69,420,000 | ||||
Balance, Treasury Shares at Jun. 30, 2021 | (10,835,000) | ||||
Shares issued - stock-based compensation | $ 11 | 241 | 252 | ||
Shares issued - stock-based compensation, Shares | 108,000 | (104,000) | |||
Stock-based compensation expense | 327 | 327 | |||
Treasury stock | $ (258) | (258) | |||
Net income (loss) | 31,721 | 31,721 | |||
Balance at Sep. 30, 2021 | $ 6,953 | $ 76,346 | $ (43,847) | $ 70,126 | $ 109,578 |
Balance, Shares at Sep. 30, 2021 | 69,528,000 | ||||
Balance, Treasury Shares at Sep. 30, 2021 | (10,939,000) | (10,939,323) |
Condensed Consolidated Statem_3
Condensed Consolidated Statements Of Cash Flows - USD ($) | 9 Months Ended | |
Sep. 30, 2021 | Sep. 30, 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income (loss) | $ 47,474,000 | $ (44,586,000) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Loss from discontinued operations, net of tax | 72,000 | 41,000 |
Depreciation, depletion and amortization | 16,928,000 | 8,116,000 |
Bargain purchase gain | (7,651,000) | |
Impairment of proved crude oil and natural gas properties | 0 | 30,625,000 |
Other amortization | 181,000 | |
Deferred taxes | (24,211,000) | 26,972,000 |
Unrealized foreign exchange gain | (342,000) | (60,000) |
Stock-based compensation | 2,098,000 | (2,097,000) |
Cash settlements paid on exercised stock appreciation rights | (3,051,000) | 0 |
Derivative instruments (gain) loss, net | 21,070,000 | (6,583,000) |
Cash settlements received (paid) on matured derivative contracts, net | (10,189,000) | 7,216,000 |
Bad debt expense and other | 814,000 | 1,140,000 |
Other operating loss, net | 440,000 | 83,000 |
Operational expenses associated with equipment and other | 835,000 | 1,418,000 |
Cash advance for other long-term assets | (1,176,000) | |
Change in operating assets and liabilities: | ||
Trade receivables | 11,156,000 | 8,255,000 |
Accounts with joint venture owners | (19,000) | 8,642,000 |
Other receivables | 94,000 | 1,333,000 |
Crude oil inventory | 4,059,000 | 291,000 |
Prepayments and other | 1,081,000 | (1,153,000) |
Value added tax and other receivables | (1,339,000) | (919,000) |
Accounts payable | (9,686,000) | (9,318,000) |
Foreign income taxes receivable/payable | (2,916,000) | (6,875,000) |
Accrued liabilities and other | 1,252,000 | (3,285,000) |
Net cash provided by continuing operating activities | 46,793,000 | 19,437,000 |
Net cash used in discontinued operating activities | (72,000) | (376,000) |
Net cash provided by operating activities | 46,721,000 | 19,061,000 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Property and equipment expenditures | (8,459,000) | (22,317,000) |
Acquisition of crude oil and natural gas properties | (22,505,000) | |
Net cash used in continuing investing activities | (30,964,000) | (22,317,000) |
Net cash used in discontinued investing activities | ||
Net cash used in investing activities | (30,964,000) | (22,317,000) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Proceeds from the issuances of common stock | 1,305,000 | |
Treasury shares | (1,426,000) | (990,000) |
Net cash used in continuing financing activities | (121,000) | (990,000) |
Net cash used in discontinued financing activities | ||
Net cash used in financing activities | (121,000) | (990,000) |
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | 15,636,000 | (4,246,000) |
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD | 61,317,000 | 59,124,000 |
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD | 76,953,000 | 54,878,000 |
Supplemental disclosure of cash flow information: | ||
Income taxes paid in-kind with crude oil | 20,103,000 | 8,738,000 |
Supplemental disclosure of non-cash investing and financing activities: | ||
Property and equipment additions incurred but not paid at end of period | 4,607,000 | 1,360,000 |
Recognition of right-of-use operating lease assets and liabilities | 1,478,000 | |
Asset retirement obligations | $ 14,564,000 | $ 359,000 |
Organization and Accounting Pol
Organization and Accounting Policies | 9 Months Ended |
Sep. 30, 2021 | |
Organization and Accounting Policies [Abstract] | |
Organization and Accounting Policies | 1. ORGANIZATION AND ACCOUNTING POLICIES VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”) is a Houston, Texas 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 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 Company has discontinued operations associated with activities in Angola, West Africa. VAALCO’s consolidated subsidiaries are 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 and VAALCO Energy (USA), Inc. 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-K for the year ended December 31, 2020, which includes a summary of the significant accounting policies. With respect to the novel strain of coronavirus (“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 restrictions 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, crude oil prices have improved, there have been no disruptions to operations since the beginning of the pandemic, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required in the three or nine months ended September 30, 2021. 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 the Company’s results of operations, cash flows and financial position, including further asset impairments. 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 and 2020 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at September 30, 2021 and 2020 include a charter payment escrow for the floating, production, storage and offloading vessel (“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: 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 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” in 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 12 for further discussion. On February 28, 2019, the Gabonese branch of an 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 the 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 new 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 totaling $ 2.9 million. In February of 2021, the Central Bank authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”) . The Company, working with Citibank, filed the application to open the account on March 12, 2021 and currently is awaiting the approval of the account from the Central Bank. Amendment No. 5 to the Etame Marin block PSC also provides that in the event the Gabonese bank fails for any reason to reimburse all of the principal and interest due, 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. 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 as 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 . 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, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $ 14.4 million ($ 9.6 million, net to VAALCO) and $ 13.4 million ($ 4.5 million, net to VAALCO), respectively. The exchange rate was XAF 566.0 = $1.00 and XAF 534.8 = $1.00 at September 30, 2021 and December 31, 2020 respectively. 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, 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 – 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 the fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (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 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 – T he 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 no 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) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) 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 calculated 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 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 inputs that are based upon 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 vessels and helicopters, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and the expense is included in either “production expense” or “general and administrative expense” in the condensed consolidated financial statements. See Note 11 for further discussion. Asset retirement obligations (“ARO”) – T he Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. T he 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. T he Company uses 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 estimate of the timing and amount to replace, remove or retire 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. 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 12 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”). 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 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 % (i ncreasing 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. See Note 6 for further discussion. Income taxes – T he Company’s 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’s 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 impact the Company’s tax liability in any given year. T he 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 Company also records as income tax expense the increase or decrease in the value of the government of Gabon’s allocation of Profit Oil, which results due to change in value from the time the obligation is originally produced to the time the obligation is actually paid or satisfied through lifting. 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-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, i t may be required to record additional deferred taxes that could have a material effect on the Company’s financial position and results of operations. See Note 15 for further discussion. 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. |
New Accounting Standards
New Accounting Standards | 9 Months Ended |
Sep. 30, 2021 | |
New Accounting Standards [Abstract] | |
New Accounting Standards | 2. NEW ACCOUNTING STANDARDS Not Yet Adopted In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 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 2016-13 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. 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU No. 2019-05 (“ASU 2019-05” ): Financial Instruments-Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 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, Financial Instruments—Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates . This amendment deferred the effective date of ASU No. 2016-13 from January 1, 2020 to January 1, 2023 for calendar year end smaller reporting companies, which includes the Company. T he Company plans to defer the implementation of ASU 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 not have a material impact on the Company's financial statements. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 9 Months Ended |
Sep. 30, 2021 | |
Acquisitions and Dispositions [Abstract] | |
Acquisitions and Dispositions | 3. ACQUISITIONS AND DISPOSITIONS Acquisition of Sasol Gabon S.A.’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 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 ” under “ Other income (expense) ” in the condensed consolidated statements of operations. An income tax benefit of $ 2.2 million, related to the bargain purchase gain, is also included in the condensed 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 $ 26.4 million and $ 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 three and nine months ended September 30, 2021 and 2020, 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. (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 three and nine months ended September 30, 2021 and 2020 , the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures . |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2021 | |
Segment Information [Abstract] | |
Segment Information | 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 two reportable operating segments is organized and managed based upon geographic location. T he 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 and 2020 as well as long-lived assets and segment assets at September 30, 2021 and December 31, 2020 are as follows: 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 (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 Information about the Company’s most significant customers The Company currently sells crude oil production from Gabon under term contracts 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 signed a new contract with ExxonMobil Sales and Supply LLC (“Exxon”) that covers sales from February 2020 through January 2022 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, 2021, revenues from sales of crude oil to Exxon were 100 % of the Company’s total revenues from customers. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 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, 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 |
Revenue
Revenue | 9 Months Ended |
Sep. 30, 2021 | |
Revenue [Abstract] | |
Revenue | 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 buyer 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. COSPAs 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. 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), 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, 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 include 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” determined based on daily production rates as well as a gross carried working interest of 7.5 % (increas ing 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 is 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 as current income tax expense. 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 be 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, the Company has a $ 2.1 million foreign income tax receivable as of September 30, 2021. As of December 31, 2020, the foreign taxes payable attributable to this obligation was $ 0.9 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, 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 |
Crude Oil and Natural Gas Prope
Crude Oil and Natural Gas Properties and Equipment | 9 Months Ended |
Sep. 30, 2021 | |
Crude Oil and Natural Gas Properties and Equipment [Abstract] | |
Crude Oil and Natural Gas Properties and Equipment | 7. CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT The Company’s crude oil and natural gas properties and equipment is comprised of the following: 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 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”), received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Consortium to operate in the Etame Marin block. T he 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 three 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 granted the Consortium the right for two 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. 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 two development wells and two appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Consortium completed the two 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 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 ten-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 Consortium an additional 2.5 % gross working interest carried by the 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 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 2021 compared to the second quarter of 2021, and that the Company incurred no significant 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 our 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 will increase to 45.9 % once the EG MMH approves a new amendment to the production sharing contract. As of September 30, 2021, 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 completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. VAALCO is now proceeding to a field development concept and will work closely with the other joint venture owners to complete this over the coming months. 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 a reas 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 million of costs were transferred to proved leasehold costs leaving a 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, 2021 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 and 2020. |
Derivatives and Fair Value
Derivatives and Fair Value | 9 Months Ended |
Sep. 30, 2021 | |
Derivatives and Fair Value [Abstract] | |
Derivatives and Fair Value | 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 as of September 30, 2021. 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 While these commodity swaps 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. T he Company does not enter into derivative instruments for speculative or trading proposes. The crude oil swap contracts 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 swap 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. The following table sets forth the gain (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 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 |
Accrued Liabilities and Other
Accrued Liabilities and Other | 9 Months Ended |
Sep. 30, 2021 | |
Accrued Liabilities and Other [Abstract] | |
Accrued Liabilities and Other | 9. ACCRUED LIABILITIES AND OTHER Accrued liabilities and other balances were comprised of the following: 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 |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2021 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | 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. The amounts paid will be reimbursed through the Cost Account and are non- refundable. The abandonment estimate used for this purpose is approximately $ 61.8 million ($ 36.4 million net to VAALCO) on an undiscounted basis. Through September 30, 2021, $ 37.9 million ($ 22.3 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the condensed consolidated balance sheet. 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 con verted to local currency with a credit back to the Gabonese branch . During the three months ended September 30, 2021, the 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 losses associated with the abandonment funding account. Amendment No. 5 to the Etame Marin block PSC provides that in the event that the Gabonese bank fails for any reason to reimburse all of the principal and interest due, 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. 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 unde r the charter through its contract term. At the Company’s election, the charter could be extended for two one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. The Company’s ne t share of the charter payment is 58.8 %, or approximately $ 19.4 million per year. Although the Company believes the need for performance under the charter guarantee is remote, the Company recorded a liability of $ 0.1 million as of September 30, 2021 and $ 0.4 million as of December 31, 2020 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO charter has $ 32.1 million in remaining gross minimum obligations as of September 30, 2021. 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 On August 31, 2021, VAALCO and its co-venturers at Etame approved 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 require 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 to $ 50 million gross ($ 26 to $ 32 million net to VAALCO) with about $ 5 million net expected in 2021 and the remainder in 2022. No other prepayments are required under the FSO Agreements until the vessel is accepted by the Company at the Etame Marin Block location. The Bareboat Contract contains purchase provisions and termination provisions. The Company does not expect to utilize the terminations provision under the FSO Agreements. Dividend Policy On August 2, 2021, the Company announced a cash dividend policy beginning in the first quarter of 2022 . Additional details of the initial record date and payable date will be announced in early 2022. 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 three wells with options to drill additional wells. The drilling rig is expected to be delivered after December 1, 2021 and before January 1, 2022. |
Leases
Leases | 9 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Leases | 11. LEASES Under ASC 842, Leases , 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”) asset and a lease liability at the present value of the future lease payments. Practical Expedients –The Company elected to use these 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 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 lease agreements for the rental of marine vessels and helicopters, warehouse and storage facilities, equipment and the FPSO. The duration for these agreements range from 12 to 26 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, 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 FPSO, helicopter, 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. In August 2021, the Company signed the FSO agreements to lease a FSO to replace the current FPSO whose term will end in September 2022. Under the terms of the Bareboat Contract, a third party is expected to improve the leased vessel in order to comply with the Company’s crude-oil production requirements. The vessel is expected to arrive on location in the Etame Marin Block in September 2022 at which time control of the vessel will transfer to the Company. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. T he 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 and 2020, the components of the lease costs and the supplemental information were as follows: 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, 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: Lease Obligation Year (in thousands) 2021 $ 3,489 2022 9,685 2023 179 13,353 Less: imputed interest 370 Total lease liabilities $ 12,983 Under the joint operating agreements, other joint venture owners are obligated to fund $ 5.5 million of the $ 13.4 million in future lease liabilities. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2021 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | 12. 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 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 Marin block PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018. In 2020, the Company recorded $ 0.4 million in additions associated with the South East Etame 4H development well and $ 0.2 million in revisions associated with a U.S. property . 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. |
Shareholders' Equity
Shareholders' Equity | 9 Months Ended |
Sep. 30, 2021 | |
Shareholders' Equity [Abstract] | |
Shareholders' Equity | 13. SHAREHOLDERS’ EQUITY Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $ 25 per share. No shares of preferred stock were issued and outstanding as of September 30, 2021 or December 31, 2020. 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, no 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 14 for further discussion. |
Stock-Based Compensation and Ot
Stock-Based Compensation and Other Benefit Plans | 9 Months Ended |
Sep. 30, 2021 | |
Stock-Based Compensation and Other Benefit Plans [Abstract] | |
Stock-Based Compensation and Other Benefit Plans | 14. 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 Board of Directors to issue various types of incentive compensation. T he 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 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, 7,558,975 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-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. T he 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, 2021, the Company settled in cash $ 3.1 million for stock appreciation rights and received $ 1.3 million for stock option exercises. During the nine months ended September 30, 2020, the Company did no t settle any stock-based 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 Board of Directors that is generally a three-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles. In March 2021, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 401,759 shares at an exercise price of $ 3.14 per share and a life of ten years . For each performance stock option award, one-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-day average, exceeds $ 3.61 per share; performance stock options with respect to one-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-day average, exceeds $ 4.15 per share; and performance stock options with respect to the remaining one-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-day average, exceeds $ 4.78 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, no 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 and 2020, 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. Nine Months Ended September 30, 2021 2020 Weighted average exercise price - ($/share) $ 3.14 $ 1.23 Expected life in years 6.0 6.0 Average expected volatility 75 % 74 % Risk-free interest rate 0.95 % 0.42 % Weighted average grant date fair value - ($/share) $ 2.07 $ 0.79 Stock option activity associated with the Monte Carlo model for the nine months ended September 30, 2021 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) (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, 2021 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) (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, 504,813 shares were added to treasury as a result of tax withholding on options exercised. During the nine months ended September 30, 2020, no 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 three-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) weeks following the date of grant). In March 2021, the Company issued 526,147 shares of service- based restricted stock to employees, with a grant date fair value of $ 3.14 per share. In June 2021, the Company issued 78,432 shares of service-based restricted stock to directors, with a grant date fair value of $ 3.06 per share. The vesting of these 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: Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Non-vested shares outstanding at January 1, 2021 1,155 $ 1.30 Awards granted 605 3.13 Awards vested ( 543 ) 1.28 Awards forfeited ( 462 ) 2.00 Non-vested shares outstanding at September 30, 2021 755 $ 2.36 During the nine months ended September 30, 2021, 68,134 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 of tax withholding on the vesting of restricted shares. Stock appreciation rights (“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 Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors. During the nine months ended September 30, 2021 and 2020, the Company did no t grant SARs to employees or directors. SAR activity for the nine months ended September 30, 2021 is provided below: 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 — — 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. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2021 | |
Income Taxes [Abstract] | |
Income Taxes | 15. INCOME TAXES The income tax provision for VAALCO consists primarily of Gabonese and United States income taxes. The Company’s operations in other 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 income tax returns in all jurisdictions where such requirements exist, with Gabon and the United States being its primary tax jurisdictions. For interim reporting periods, the Company determines its tax expense by estimating an annual effective 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 recognized in the period in which they occur at the applicable statutory tax rate. Provision for income tax expense (benefit) related to income from continuing operations consists of the following: 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 and 2020, excluding the impact of discrete items, was 37.5 % and ( 53 %), respectively. For the nine months ended September 30, 2021, the Company’s overall effective tax rate was impacted by non-deductible items associated with operations, the impact of deducting foreign taxes rather than crediting them, and a change in valuation allowance. Prior to September 30, 2021, the 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 observation of the increasing crude oil prices over a sustained period of time, lack of disruption in operations due to the pandemic, steady increase in global economic activity and oil supply demand over multiple quarters has removed much of 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, the current tax expense of $ 5.5 million includes a $ 0.2 million unfavorable oil price adjustment as a result of the change in value of the government’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 $ 5.3 million for the period. For the nine months ended September 30, 2021, the current tax expense of $ 15.1 million includes a $ 1.7 million unfavorable oil price adjustment as a result of the change in value of the government’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 million for the period. As of September 30, 2021, the Company had no 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. |
Organization and Accounting P_2
Organization and Accounting Policies (Policy) | 9 Months Ended |
Sep. 30, 2021 | |
Organization and Accounting Policies [Abstract] | |
Nature of Operations | VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”) is a Houston, Texas 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 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 Company has discontinued operations associated with activities in Angola, West Africa. VAALCO’s consolidated subsidiaries are 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 and VAALCO Energy (USA), Inc. |
Principles of Consolidation | 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. |
Basis of Accounting | 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-K for the year ended December 31, 2020, which includes a summary of the significant accounting policies. |
COVID-19 | With respect to the novel strain of coronavirus (“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 restrictions 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, crude oil prices have improved, there have been no disruptions to operations since the beginning of the pandemic, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required in the three or nine months ended September 30, 2021. 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 the Company’s results of operations, cash flows and financial position, including further asset impairments. |
Restricted Cash and Abandonment Funding | 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 and 2020 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at September 30, 2021 and 2020 include a charter payment escrow for the floating, production, storage and offloading vessel (“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: 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 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” in 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 12 for further discussion. On February 28, 2019, the Gabonese branch of an 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 the 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 new 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 totaling $ 2.9 million. In February of 2021, the Central Bank authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”) . The Company, working with Citibank, filed the application to open the account on March 12, 2021 and currently is awaiting the approval of the account from the Central Bank. Amendment No. 5 to the Etame Marin block PSC also provides that in the event the Gabonese bank fails for any reason to reimburse all of the principal and interest due, 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. |
Accounts Receivable and Allowance for Doubtful Accounts | 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 as 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 . 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, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $ 14.4 million ($ 9.6 million, net to VAALCO) and $ 13.4 million ($ 4.5 million, net to VAALCO), respectively. The exchange rate was XAF 566.0 = $1.00 and XAF 534.8 = $1.00 at September 30, 2021 and December 31, 2020 respectively. 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, 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 | 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 the fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (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 – 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 Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). |
Stock-Based Compensation | 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 | Fair value of financial instruments – T he 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 no 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 | 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 | 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) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) 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 | 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 calculated 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 five years for office and miscellaneous equipment and five to seven years for leasehold improvements. See Note 7 for further discussion. |
Impairment | 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 inputs that are based upon 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 | 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 | Lease commitments – The Company leases office space, marine vessels and helicopters, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and the expense is included in either “production expense” or “general and administrative expense” in the condensed consolidated financial statements. See Note 11 for further discussion. |
Asset Retirement Obligations ("ARO") | Asset retirement obligations (“ARO”) – T he Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. T he 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. T he Company uses 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 estimate of the timing and amount to replace, remove or retire 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. 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 12 for further discussion. |
Revenue Recognition | Revenue recognition – Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPA”). 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 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 % (i ncreasing 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. See Note 6 for further discussion. |
Income Taxes | Income taxes – T he Company’s 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’s 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 impact the Company’s tax liability in any given year. T he 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 Company also records as income tax expense the increase or decrease in the value of the government of Gabon’s allocation of Profit Oil, which results due to change in value from the time the obligation is originally produced to the time the obligation is actually paid or satisfied through lifting. 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-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, i t may be required to record additional deferred taxes that could have a material effect on the Company’s financial position and results of operations. See Note 15 for further discussion. |
Earnings per Share | 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. |
Organization and Accounting P_3
Organization and Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Organization and Accounting Policies [Abstract] | |
Reconciliation of Cash, Cash Equivalents, and Restricted Cash | 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 |
Rollforward of 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 ) |
Assets and Liabilities Measured on Recurring Basis | 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 |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Acquisitions and Dispositions [Abstract] | |
Fair Value of Assets and Liabilities Acquired | 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 |
Pro Forma Results of Acquisition | 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. (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. |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Segment Information [Abstract] | |
Segment Activity | 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 |
Long-lived Assets From Continuing Operations | (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 (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 Information |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Schedule of Diluted Shares | 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 |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Revenue [Abstract] | |
Revenues from Contracts with Customers | 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 |
Crude Oil and Natural Gas Pro_2
Crude Oil and Natural Gas Properties and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Crude Oil and Natural Gas Properties and Equipment [Abstract] | |
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 |
Derivatives and Fair Value (Tab
Derivatives and Fair Value (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Derivatives and Fair Value [Abstract] | |
Summary of Commodity Swaps | 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 |
Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations | 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 |
Accrued Liabilities and Other (
Accrued Liabilities and Other (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Accrued Liabilities and Other [Abstract] | |
Schedule of Accrued Liabilities and Other Balances | 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 |
Leases (Tables)
Leases (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Components of Lease Costs | 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 % |
Lease Cost on Consolidated Statement of Operations | 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 |
Schedule of Future Maturities of Operating Lease Liabilities | Lease Obligation Year (in thousands) 2021 $ 3,489 2022 9,685 2023 179 13,353 Less: imputed interest 370 Total lease liabilities $ 12,983 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Asset Retirement Obligations [Abstract] | |
Summary of Changes in 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 |
Stock-Based Compensation and _2
Stock-Based Compensation and Other Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Stock-Based Compensation and Other Benefit Plans [Abstract] | |
Summary of Stock-Based Compensation | 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 Option Valuation Assumptions | Nine Months Ended September 30, 2021 2020 Weighted average exercise price - ($/share) $ 3.14 $ 1.23 Expected life in years 6.0 6.0 Average expected volatility 75 % 74 % Risk-free interest rate 0.95 % 0.42 % Weighted average grant date fair value - ($/share) $ 2.07 $ 0.79 |
Stock Option Activity | Stock option activity associated with the Monte Carlo model for the nine months ended September 30, 2021 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) (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, 2021 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) (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 |
Summary of Non Vested Awards | Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Non-vested shares outstanding at January 1, 2021 1,155 $ 1.30 Awards granted 605 3.13 Awards vested ( 543 ) 1.28 Awards forfeited ( 462 ) 2.00 Non-vested shares outstanding at September 30, 2021 755 $ 2.36 |
SAR Activity | 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 — — 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 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Income Taxes [Abstract] | |
Provision for Income Taxes | 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 |
Organization and Accounting P_4
Organization and Accounting Policies (Narrative) (Details) | Jun. 20, 2026 | Feb. 25, 2021 | Sep. 30, 2021USD ($) / $ | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($) / $ | Sep. 30, 2020USD ($) | Dec. 31, 2020USD ($) / $ | Feb. 24, 2021 |
Organization And Accounting Policies [Line Items] | ||||||||
Impairment of proved crude oil and natural gas properties | $ 0 | $ 0 | $ 0 | $ 30,625,000 | ||||
Receivable balance, gross, noncurrent | $ 9,600,000 | $ 9,600,000 | $ 4,500,000 | |||||
Abandonment funding payments missed | $ 2,900,000 | |||||||
Exchange rate | / $ | 566 | 566 | 534.8 | |||||
Transfers between levels | $ 0 | $ 0 | ||||||
Office and Miscellaneous Equipment [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Estimated useful life of assets | 5 years | |||||||
Leasehold Improvements [Member] | Minimum [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Estimated useful life of assets | 5 years | |||||||
Leasehold Improvements [Member] | Maximum [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Estimated useful life of assets | 7 years | |||||||
Consortium [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Receivable balance, gross, noncurrent | $ 14,400,000 | $ 14,400,000 | $ 13,400,000 | |||||
Prior Production Sharing Contract, Through September 17, 2018 [Member] | Government Of Gabon [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Monthly royalty rate, based on production at the published price | 13.00% | |||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Monthly royalty rate, based on production at the published price | 13.00% | |||||||
Etame Marine Block [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Impairment of proved crude oil and natural gas properties | $ 30,600,000 | |||||||
Working interest ownership, percentage | 58.80% | 31.10% | ||||||
Etame Marine Block [Member] | Sasol Gabon S.A. [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Increase (decrease) in working interest ownership percentage | 27.80% | |||||||
Etame Marine Block [Member] | Prior Production Sharing Contract, Through September 17, 2018 [Member] | Consortium [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Working interest ownership, percentage | 7.50% | 7.50% | ||||||
Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Working interest ownership, percentage | 7.50% | 7.50% | ||||||
Etame Marine Block [Member] | Scenario, Forecast [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Increase (decrease) in working interest ownership percentage | (1.60%) | |||||||
Etame Marine Block [Member] | Scenario, Forecast [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||||
Organization And Accounting Policies [Line Items] | ||||||||
Increase (decrease) in working interest ownership percentage | 2.50% | |||||||
Working interest ownership, percentage | 10.00% |
Organization and Accounting P_5
Organization and Accounting Policies (Reconciliation of Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Dec. 31, 2019 |
Organization and Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 52,839 | $ 47,853 | $ 41,986 | |
Restricted cash - current | 81 | 86 | 82 | |
Restricted cash - non-current | 1,752 | 925 | 925 | |
Abandonment funding | 22,281 | 12,453 | 11,885 | |
Total cash, cash equivalents and restricted cash | $ 76,953 | $ 61,317 | $ 54,878 | $ 59,124 |
Organization and Accounting P_6
Organization and Accounting Policies (Rollforward of Aggregate Allowance for Bad Debt) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Organization and Accounting Policies [Abstract] | ||||
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) |
Organization and Accounting P_7
Organization and Accounting Policies (Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
SARs liability | $ 761 | $ 2,289 |
Derivative liability - crude oil swaps | 10,881 | |
SARs liability | 193 | |
Liabilities | 11,642 | 2,482 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
SARs liability | 761 | 2,289 |
Derivative liability - crude oil swaps | 10,881 | |
SARs liability | 193 | |
Liabilities | $ 11,642 | $ 2,482 |
Acquisitions and Dispositions_2
Acquisitions and Dispositions (Narrative) (Details) $ in Thousands | Feb. 25, 2021USD ($) | Nov. 30, 2006 | Sep. 30, 2021USD ($) | Jun. 30, 2021USD ($) | Mar. 31, 2021USD ($) | Sep. 30, 2020USD ($) | Jun. 30, 2020USD ($) | Mar. 31, 2020USD ($) | Sep. 30, 2021USD ($)$ / bbl | Sep. 30, 2020USD ($) | Apr. 29, 2021USD ($) | Feb. 24, 2021 |
Business Acquisition [Line Items] | ||||||||||||
Bargain purchase gain | $ (7,651) | |||||||||||
Revenues | $ 55,899 | $ 18,256 | 142,696 | $ 54,619 | ||||||||
Net income | 31,721 | $ 5,884 | $ 9,869 | $ 7,618 | $ 596 | $ (52,800) | 47,474 | $ (44,586) | ||||
Sasol Gabon S.A. [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Bargain purchase gain | $ (7,700) | |||||||||||
Bargain purchase gain, net of tax | 5,500 | |||||||||||
Bargain purchase gain, income tax benefit | 2,200 | |||||||||||
Revenues | 26,400 | 58,000 | ||||||||||
Net income | $ 10,200 | $ 20,100 | ||||||||||
Contingent consideration | $ 5,000 | $ 5,000 | ||||||||||
Contingent consideration, measurement period of oil price | 90 days | |||||||||||
Contingent consideration, oil price threshold | $ / bbl | 60 | |||||||||||
Discontinued Operations [Member] | Joint Operating With Republic Of Angola [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Joint operation agreement related to third party in working interest percentage | 40.00% | |||||||||||
Additional joint operation agreement related to third party in working interest percentage | 10.00% | |||||||||||
Etame Marine Block [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Working interest ownership, percentage | 58.80% | 31.10% | ||||||||||
Etame Marine Block [Member] | Sasol Gabon S.A. [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Increase (decrease) in working interest ownership percentage | 27.80% |
Acquisitions and Dispositions_3
Acquisitions and Dispositions (Fair Value of Assets and Liabilities Acquired) (Details) - Sasol Gabon S.A. [Member] $ in Thousands | Feb. 25, 2021USD ($) |
Business Acquisition [Line Items] | |
Cash | $ 33,959 |
Fair value of contingent consideration | 4,647 |
Total purchase consideration | 38,606 |
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 |
Asset retirement obligations | (14,564) |
Accrued liabilities and other | (10,121) |
Bargain purchase gain | (7,651) |
Total purchase price | $ 38,606 |
Acquisitions and Dispositions_4
Acquisitions and Dispositions (Pro Forma Results of Acquisition) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |||
Business Acquisition [Line Items] | ||||||
Basic weighted average shares outstanding | 58,586 | 57,456 | 58,102 | 57,628 | ||
Diluted weighted average shares outstanding | 58,916 | 57,741 | 58,654 | 57,628 | ||
Sasol Gabon S.A. [Member] | ||||||
Business Acquisition [Line Items] | ||||||
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 | [1] | $ 9,136 | $ 49,341 | [1] | $ (36,316) |
Income (loss) from continuing operations | $ 0.53 | $ 0.16 | $ 0.85 | $ (0.63) | ||
Loss from discontinued operations, net of tax | 0 | 0 | 0 | 0 | ||
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 | ||
Income (loss) from continuing operations | $ 0.53 | $ 0.16 | $ 0.84 | $ (0.63) | ||
Loss from discontinued operations, net of tax | 0 | 0 | 0 | 0 | ||
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 | ||
Sasol Gabon S.A. [Member] | Bargain Purchase Gain [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Net income (loss) | $ (7,700) | $ (7,700) | ||||
Sasol Gabon S.A. [Member] | Acquisition-related Costs [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Net income (loss) | $ (1,000) | $ (1,000) | ||||
[1] | 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. |
Segment Information (Narrative)
Segment Information (Narrative) (Details) - segment | 3 Months Ended | 9 Months Ended |
Sep. 30, 2021 | Sep. 30, 2021 | |
Concentration Risk [Line Items] | ||
Number of reportable operating segments | 2 | |
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | ||
Concentration Risk [Line Items] | ||
Concentration risk, percentage | 100.00% | 100.00% |
Segment Information (Segment Ac
Segment Information (Segment Activity) (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Segment Reporting Information [Line Items] | ||||
Revenues-crude oil and natural gas sales | $ 55,899,000 | $ 18,256,000 | $ 142,696,000 | $ 54,619,000 |
Depreciation, depletion and amortization | 6,970,000 | 2,212,000 | 16,928,000 | 8,116,000 |
Impairment of proved crude oil and natural gas properties | 0 | 0 | 0 | 30,625,000 |
Bad debt expense and other | 318,000 | 151,000 | 814,000 | 1,140,000 |
Other operating income (expense), net | 46,000 | (37,000) | (440,000) | (883,000) |
Operating income (loss) | 20,030,000 | 4,678,000 | 53,247,000 | (22,971,000) |
Derivative instruments gain (loss), net | (5,147,000) | (21,070,000) | 6,583,000 | |
Other, net | (328,000) | 147,000 | 4,088,000 | 163,000 |
Income tax expense (benefit) | (17,183,000) | (2,759,000) | (11,272,000) | 28,470,000 |
Additions to crude oil and natural gas properties and equipment - accrual | 6,696,000 | (315,000) | 10,993,000 | 10,296,000 |
Operating Segments [Member] | Gabon Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues-crude oil and natural gas sales | 55,899,000 | 18,256,000 | 142,696,000 | 54,619,000 |
Depreciation, depletion and amortization | 6,953,000 | 1,946,000 | 16,860,000 | 7,790,000 |
Impairment of proved crude oil and natural gas properties | 30,625,000 | |||
Bad debt expense and other | 151,000 | 814,000 | 1,140,000 | |
Other operating income (expense), net | (440,000) | (883,000) | ||
Operating income (loss) | 22,834,000 | 6,957,000 | 64,933,000 | (17,622,000) |
Other, net | 7,207,000 | |||
Income tax expense (benefit) | 436,000 | (2,464,000) | 8,396,000 | 19,302,000 |
Additions to crude oil and natural gas properties and equipment - accrual | 6,696,000 | (306,000) | 10,993,000 | 10,305,000 |
Operating Segments [Member] | Equatorial Guinea Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Operating income (loss) | (271,000) | (95,000) | (505,000) | (289,000) |
Other, net | (2,000) | |||
Income tax expense (benefit) | 1,000 | 1,000 | 1,000 | |
Corporate and Other [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Depreciation, depletion and amortization | 17,000 | 266,000 | 68,000 | 326,000 |
Operating income (loss) | (2,533,000) | (2,184,000) | (11,181,000) | (5,060,000) |
Derivative instruments gain (loss), net | (5,147,000) | (21,070,000) | 6,583,000 | |
Other, net | (3,117,000) | |||
Income tax expense (benefit) | $ (17,619,000) | (296,000) | $ (19,669,000) | 9,167,000 |
Additions to crude oil and natural gas properties and equipment - accrual | $ (9,000) | $ (9,000) |
Segment Information (Long-lived
Segment Information (Long-lived Assets From Continuing Operations) (Details) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Segment Reporting Information [Line Items] | ||
Total assets | $ 206,260 | $ 141,232 |
Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 74,102 | 37,036 |
Total assets | 206,260 | 141,232 |
Operating Segments [Member] | Gabon Segment [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 63,966 | 26,832 |
Total assets | 149,188 | 101,399 |
Operating Segments [Member] | Equatorial Guinea Segment [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 10,000 | 10,000 |
Total assets | 10,430 | 10,267 |
Corporate and Other [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 136 | 204 |
Total assets | $ 46,642 | $ 29,566 |
Earnings Per Share (Schedule of
Earnings Per Share (Schedule of Diluted Shares) (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Schedule of Diluted shares | ||||||||
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) | ||||
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) | ||||
Numerator for dilutive | (20) | 11 | (71) | (41) | ||||
Net income (loss) | 31,721 | $ 5,884 | $ 9,869 | 7,618 | $ 596 | $ (52,800) | 47,474 | (44,586) |
Net income attributable to unvested shares | (404) | (121) | (754) | |||||
Numerator for basic | 31,317 | 7,497 | 46,720 | (44,586) | ||||
Numerator for dilutive | $ 31,317 | $ 7,497 | $ 46,720 | $ (44,586) | ||||
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 |
Revenue (Narrative) (Details)
Revenue (Narrative) (Details) - USD ($) $ in Thousands | 9 Months Ended | |||||
Sep. 30, 2021 | Sep. 30, 2020 | Jun. 20, 2026 | Feb. 25, 2021 | Feb. 24, 2021 | Dec. 31, 2020 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Interval period, between lifting | 30 days | |||||
Foreign income taxes receivable | $ 2,056 | |||||
Foreign taxes payable attributable to sharing obligation | $ 900 | |||||
Income taxes paid in-kind with crude oil | $ 20,103 | $ 8,738 | ||||
Minimum [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Lifting period, time to complete | 1 day | |||||
Maximum [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Lifting period, time to complete | 2 days | |||||
Prior Production Sharing Contract, Through September 17, 2018 [Member] | Government Of Gabon [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Monthly royalty rate, based on production at the published price | 13.00% | |||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Purchase agreement payment period | 30 days | |||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Monthly royalty rate, based on production at the published price | 13.00% | |||||
Etame Marine Block [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Working interest ownership, percentage | 58.80% | 31.10% | ||||
Etame Marine Block [Member] | Prior Production Sharing Contract, Through September 17, 2018 [Member] | Consortium [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Working interest ownership, percentage | 7.50% | |||||
Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Working interest ownership, percentage | 7.50% | |||||
Etame Marine Block [Member] | Scenario, Forecast [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government Of Gabon [Member] | ||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||||||
Working interest ownership, percentage | 10.00% |
Revenue (Revenues from Contract
Revenue (Revenues from Contracts with Customers) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Disaggregation of Revenue [Line Items] | ||||
Carried interest recoupment | $ 1,794 | $ 280 | $ 5,948 | $ 1,273 |
Royalties | (8,054) | (2,704) | (20,048) | (8,449) |
Total revenue, net | 55,899 | 18,256 | 142,696 | 54,619 |
Sales Under COSPA [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Sales under the COSPA | 42,056 | 13,797 | 136,693 | 53,057 |
Gabonese Government Share Of Profit Oil [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Sales under the COSPA | $ 20,103 | $ 6,883 | $ 20,103 | $ 8,738 |
Crude Oil and Natural Gas Pro_3
Crude Oil and Natural Gas Properties and Equipment (Narrative) (Details) | Jun. 20, 2026 | Apr. 12, 2021 | Feb. 25, 2021 | Sep. 26, 2018USD ($) | Sep. 17, 2018USD ($)item | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($)item | Sep. 30, 2020USD ($) | Dec. 31, 2020USD ($) | Feb. 24, 2021 | Mar. 31, 2020USD ($) | Dec. 31, 2012 |
Property, Plant and Equipment [Line Items] | ||||||||||||||
Reduction in VAT receivable | $ (1,339,000) | $ (919,000) | ||||||||||||
Impairment of proved crude oil and natural gas properties | $ 0 | $ 0 | 0 | 30,625,000 | ||||||||||
Property, net | $ 74,102,000 | $ 74,102,000 | $ 37,036,000 | |||||||||||
Etame Marine Block [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 58.80% | 31.10% | ||||||||||||
Impairment of proved crude oil and natural gas properties | 30,600,000 | |||||||||||||
Property, net | $ 15,600,000 | $ 15,600,000 | $ 15,600,000 | |||||||||||
Undeveloped acreage | $ 2,300,000 | |||||||||||||
Undeveloped leasehold value | $ 11,500,000 | |||||||||||||
Etame Marine Block [Member] | VAALCO Gabon S.A. [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 63.575% | 63.575% | ||||||||||||
Prior Production Sharing Contract, Through September 17, 2018 [Member] | Etame Marine Block [Member] | Consortium [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 7.50% | 7.50% | ||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Deferred tax assets, basis difference in fixed assets | $ 18,600,000 | $ 18,600,000 | ||||||||||||
Estimated costs of technical studies | 500,000 | |||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Consortium [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Number of wells drilled | item | 2 | |||||||||||||
Number of wellbores drilled | item | 2 | |||||||||||||
Number of technical studies required | item | 2 | |||||||||||||
Estimated costs of technical studies | $ 1,500,000 | |||||||||||||
Entitled percent for consortium after initial royalty percentage | 80.00% | |||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Signing Bonus [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Contractual obligation | $ 21,800,000 | |||||||||||||
Payment of signing bonus, allocated to proved and unproved property | $ 11,800,000 | |||||||||||||
Reduction in VAT receivable | 8,400,000 | |||||||||||||
Other accrued liabilities | 1,700,000 | |||||||||||||
Allocated to unproved leasehold cost | 6,700,000 | $ 6,700,000 | ||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Signing Bonus [Member] | Consortium [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Contractual obligation | $ 65,000,000 | |||||||||||||
Payment of signing bonus, allocated to proved and unproved property | 35,000,000 | |||||||||||||
Reduction in VAT receivable | 25,000,000 | |||||||||||||
Other accrued liabilities | $ 5,000,000 | |||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Tax Impact [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Allocated to unproved leasehold cost | $ 7,100,000 | $ 7,100,000 | ||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Etame Marine Block [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Number of exploitation areas | item | 3 | |||||||||||||
Period of agreement for exploitation areas | 10 years | 10 years | ||||||||||||
Number of contract extension periods | item | 2 | |||||||||||||
Production license agreement term extended by government | 5 years | |||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Etame Marine Block [Member] | Government Of Gabon [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 7.50% | 7.50% | ||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Scenario, Forecast [Member] | Etame Marine Block [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Increase (decrease) in working interest ownership percentage | (1.60%) | |||||||||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Scenario, Forecast [Member] | Etame Marine Block [Member] | Government Of Gabon [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 10.00% | |||||||||||||
Increase (decrease) in working interest ownership percentage | 2.50% | |||||||||||||
Production Sharing Contract, After September 16, 2028 [Member] | Consortium [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Entitled percent for consortium after initial royalty percentage | 70.00% | |||||||||||||
Sasol Gabon S.A. [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Undeveloped acreage | $ 2,200,000 | $ 2,200,000 | ||||||||||||
Sasol Gabon S.A. [Member] | Etame Marine Block [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Increase (decrease) in working interest ownership percentage | 27.80% | |||||||||||||
Undeveloped leasehold value | 13,700,000 | 13,700,000 | ||||||||||||
Block P Offshore Equatorial Guinea [Member] | ||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||
Working interest ownership, percentage | 43.00% | 31.00% | ||||||||||||
Increase (decrease) in working interest ownership percentage | 45.90% | 12.00% | ||||||||||||
Undeveloped acreage | $ 10,000,000 | $ 10,000,000 | ||||||||||||
Potential payment | $ 3,100,000 | |||||||||||||
Period of development | 25 years |
Crude Oil and Natural Gas Pro_4
Crude Oil and Natural Gas Properties and Equipment (Crude Oil and Natural Gas Properties and Equipment) (Details) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Property, Plant and Equipment [Line Items] | ||
Gross crude oil and natural gas properties and equipment | $ 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 |
Wells, Platforms and Other Production Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross crude oil and natural gas properties and equipment | 480,872 | 441,879 |
Work-in-Progress [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross crude oil and natural gas properties and equipment | 2,278 | 169 |
Undeveloped Acreage [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross crude oil and natural gas properties and equipment | 23,735 | 21,476 |
Equipment and Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross crude oil and natural gas properties and equipment | $ 18,694 | $ 9,276 |
Derivatives and Fair Value (Nar
Derivatives and Fair Value (Narrative) (Details) | Aug. 06, 2021$ / bblbbl | May 06, 2021$ / bblbbl | Jan. 22, 2021$ / bblbbl | May 06, 2019$ / bblbbl | Sep. 30, 2021$ / bblbbl |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Barrels | 1,119,723 | ||||
Commodity Contract, July 2019 Through June 2020 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative, average price per barrel | $ / bbl | 66.70 | ||||
Barrels | 500,000 | ||||
Commodity Contract, February 2021 Through January 2022 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative, average price per barrel | $ / bbl | 53.10 | ||||
Barrels | 709,262 | ||||
Commodity Contract, May 2021 Through October 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative, average price per barrel | $ / bbl | 66.51 | ||||
Barrels | 672,533 | ||||
Commodity Contract Three - November 2021 To February 2022 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative, average price per barrel | $ / bbl | 67.70 | 67.70 | |||
Barrels | 314,420 | 314,420 | |||
Commodity Contract Four - March 2022 To June 2022 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative, average price per barrel | $ / bbl | 72 | ||||
Barrels | 460,000 |
Derivatives and Fair Value (Sum
Derivatives and Fair Value (Summary of Commodity Swaps) (Details) | Aug. 06, 2021$ / bblbbl | Sep. 30, 2021$ / bblbbl |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Barrels | 1,119,723 | |
Commodity Contract One - October 2021 To January 2022 [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Barrels | 236,421 | |
Weighted Average Fixed Price | $ / bbl | 53.10 | |
Commodity Contract Two - October 2021 [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Barrels | 108,882 | |
Weighted Average Fixed Price | $ / bbl | 66 | |
Commodity Contract Three - November 2021 To February 2022 [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Barrels | 314,420 | 314,420 |
Weighted Average Fixed Price | $ / bbl | 67.70 | 67.70 |
Commodity Contract Four - March 2022 To June 2022 [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Barrels | 460,000 | |
Weighted Average Fixed Price | $ / bbl | 72 |
Derivatives and Fair Value (Eff
Derivatives and Fair Value (Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations) (Details) - Crude Oil Swaps [Member] - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2021 | Sep. 30, 2021 | Sep. 30, 2020 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative instruments gain (loss), net | $ (5,147) | $ (21,070) | $ 6,583 |
Realized Gain (Loss) - Contract Settlements [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative instruments gain (loss), net | (4,186) | (10,189) | 7,216 |
Unrealized Loss [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative instruments gain (loss), net | $ (961) | $ (10,881) | $ (633) |
Accrued Liabilities and Other_2
Accrued Liabilities and Other (Schedule of Accrued Liabilities and Other Balances) (Details) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Accrued Liabilities and Other [Abstract] | ||
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 |
Commitments and Contingencies (
Commitments and Contingencies (Narrative) (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||
Dec. 31, 2021USD ($)item | Aug. 31, 2020USD ($)km² | Jun. 30, 2020USD ($) | Sep. 30, 2021USD ($) | Sep. 30, 2021USD ($)item | Dec. 31, 2022USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Sep. 30, 2020USD ($) | |
Commitments And Contingencies [Line Items] | |||||||||
Abandonment funding | $ 22,281 | $ 22,281 | $ 12,453 | $ 11,885 | |||||
Foreign currency gain on abandonment funding | (600) | (1,100) | |||||||
Agreement prepayment | (1,176) | ||||||||
Agreement prepayment, recoverable amount | 6,000 | 6,000 | |||||||
Etame Marine Block [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated abandonment costs | 36,400 | 36,400 | |||||||
Abandonment funding | 22,300 | $ 22,300 | |||||||
Payment of joint venture audit settlement | $ 800 | ||||||||
Area of three-dimensional seismic data | km² | 1,000 | ||||||||
Etame Marine Block [Member] | Minimum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Expected cost of data acquisition | $ 2,200 | ||||||||
Etame Marine Block [Member] | Maximum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Expected cost of data acquisition | $ 3,400 | ||||||||
FPSO Charter [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Number of extensions | item | 2 | ||||||||
Period of charter | 1 year | ||||||||
Guarantee liability | 100 | $ 100 | $ 400 | ||||||
Percentage of share in charter payment | 58.80% | ||||||||
Share in charter payment, approximate annual amount | $ 19,400 | ||||||||
Consortium [Member] | Etame Marine Block [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated abandonment costs | 61,800 | 61,800 | |||||||
Abandonment funding | 37,900 | 37,900 | |||||||
Consortium [Member] | FPSO Charter [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Maximum exposure | $ 32,100 | $ 32,100 | |||||||
Scenario, Forecast [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Agreement prepayment | $ 3,200 | $ 1,300 | |||||||
Estimated field level capital conversion | $ 5,000 | 5,000 | |||||||
Scenario, Forecast [Member] | Minimum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated field level capital conversion | 26,000 | ||||||||
Scenario, Forecast [Member] | Maximum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated field level capital conversion | 32,000 | ||||||||
Scenario, Forecast [Member] | Consortium [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Agreement prepayment | 5,000 | $ 2,000 | |||||||
Scenario, Forecast [Member] | Consortium [Member] | Minimum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated field level capital conversion | 40,000 | ||||||||
Scenario, Forecast [Member] | Consortium [Member] | Maximum [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Estimated field level capital conversion | $ 50,000 | ||||||||
Scenario, Forecast [Member] | Borr Drilling [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Number Of Drilled Wells Required By Agreement | item | 3 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) $ in Thousands | Sep. 30, 2021USD ($) |
Lessee, Lease, Description [Line Items] | |
Joint owner obligation | $ 5,500 |
Future lease liabilities | $ 13,353 |
Maximum [Member] | |
Lessee, Lease, Description [Line Items] | |
Lease terms | 26 months |
Minimum [Member] | |
Lessee, Lease, Description [Line Items] | |
Lease terms | 12 months |
Leases (Components of Lease Cos
Leases (Components of Lease Costs) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Leases [Abstract] | ||||
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 |
Operating cash flows attributable to operating leases | $ 18,018 | $ 20,564 | ||
Weighted-average remaining lease term | 1 year | 2 years | 1 year | 2 years |
Weighted-average discount rate | 6.09% | 6.09% | 6.09% | 6.09% |
Leases (Lease Cost on Consolida
Leases (Lease Cost on Consolidated Statement of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Lease Costs [Line Items] | ||||
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 |
Production Expense [Member] | ||||
Lease Costs [Line Items] | ||||
Total lease expense | 3,827 | 2,063 | 10,328 | 6,082 |
General and Administrative Expense [Member] | ||||
Lease Costs [Line Items] | ||||
Total lease expense | 49 | 49 | 145 | 147 |
Lease Costs Billed To The Joint Venture Owners [Member] | ||||
Lease Costs [Line Items] | ||||
Total lease expense | $ 2,679 | $ 4,586 | $ 9,266 | $ 15,807 |
Leases (Schedule of Future Matu
Leases (Schedule of Future Maturities of Operating Lease Liabilities) (Details) $ in Thousands | Sep. 30, 2021USD ($) |
Leases [Abstract] | |
2021 | $ 3,489 |
2022 | 9,685 |
2023 | 179 |
Total lease payments | 13,353 |
Less: imputed interest | 370 |
Total lease liabilities | $ 12,983 |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligations [Abstract] | ||
Additions | $ 14,564 | $ 359 |
Revisions | $ 238 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Summary of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligations [Abstract] | ||
Beginning balance | $ 17,334 | $ 15,844 |
Accretion | 1,179 | 893 |
Additions | 14,564 | 359 |
Revisions | 238 | |
Ending balance | $ 33,077 | $ 17,334 |
Shareholders' Equity (Narrative
Shareholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 10 Months Ended | |||||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2021 | Apr. 13, 2020 | Dec. 31, 2020 | Jun. 20, 2019 | |
Class of Stock [Line Items] | ||||||||||
Preferred stock, shares authorized | 500,000 | 500,000 | 500,000 | |||||||
Preferred stock, par value | $ 25 | $ 25 | $ 25 | |||||||
Preferred stock, shares issued | 0 | 0 | 0 | |||||||
Preferred stock, shares outstanding | 0 | 0 | 0 | |||||||
Price of shares repurchased | $ 258 | $ 765 | $ 403 | $ 338 | $ 652 | |||||
2019 Repurchase Program [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Preferred stock, shares authorized | 0 | |||||||||
Stock repurchase program, amount authorized | $ 10,000 | |||||||||
Stock repurchase program, period in force | 12 months | |||||||||
Shares repurchased | 2,740,643 | |||||||||
Average price per share | $ 1.70 | |||||||||
Price of shares repurchased | $ 4,700 |
Stock-Based Compensation and _3
Stock-Based Compensation and Other Benefit Plans (Narrative) (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2021 | Sep. 30, 2021 | Sep. 30, 2020 | Jun. 25, 2020 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Payments to settle stock appreciation rights | $ 3,051,000 | $ 0 | ||||
Proceeds from stock options exercised | $ 1,300,000 | |||||
Options granted | 401,759 | |||||
Options granted, weighted average exercise price | $ 3.14 | |||||
Severance cost as percentage of target bonus | 75.00% | |||||
Long-Term Incentive Plan, 2020 [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Awards authorized | 5,500,000 | |||||
Increase in shares authorized | 3,750,000 | |||||
Awards available | 7,558,975 | 7,558,975 | ||||
Performance Shares [Member] | Long-Term Incentive Plan, 2020 [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Other awards exercised | 0 | 0 | ||||
Stock Option [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Award granted life | 10 years | |||||
Shares withheld to satisfy tax withholding obligations | 504,813 | 0 | ||||
Stock Option [Member] | Share-based Payment Arrangement, Tranche One [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Vesting percentage | 33.33% | |||||
Share price for vesting scheme | $ 3.61 | |||||
Stock Option [Member] | Share-based Payment Arrangement, Tranche Two [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Vesting percentage | 33.33% | |||||
Share price for vesting scheme | $ 4.15 | |||||
Stock Option [Member] | Share-based Payment Arrangement, Tranche Three [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Vesting percentage | 33.33% | |||||
Share price for vesting scheme | $ 4.78 | |||||
Restricted Stock [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Awards, vesting period | 3 years | |||||
Shares withheld to satisfy tax withholding obligations | 68,134 | 40,432 | ||||
Other awards granted | 605,000 | |||||
Other awards granted, weighted average exercise price | $ 3.13 | |||||
Restricted Stock [Member] | Employees [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Other awards granted | 78,432 | 526,147 | ||||
Other awards granted, weighted average exercise price | $ 3.06 | $ 3.14 | ||||
Stock Appreciation Rights (SARs) [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Other awards granted | 0 | 0 | ||||
Minimum [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Severance cost as percentage of salary | 50.00% | |||||
Maximum [Member] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Severance cost as percentage of salary | 100.00% |
Stock-Based Compensation and _4
Stock-Based Compensation and Other Benefit Plans (Summary of Stock-Based Compensation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Total stock-based compensation | $ 25 | $ (248) | $ 2,098 | $ (2,097) |
Equity Award [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Total stock-based compensation | 327 | 322 | 767 | 527 |
Liability Award [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Total stock-based compensation | $ (302) | $ (570) | $ 1,331 | $ (2,624) |
Stock-Based Compensation and _5
Stock-Based Compensation and Other Benefit Plans (Stock Option Valuation Assumptions) (Details) - $ / shares | 9 Months Ended | |
Sep. 30, 2021 | Sep. 30, 2020 | |
Valuation of the options granted | ||
Weighted average exercise price - ($/share) | $ 3.14 | $ 1.23 |
Expected life in years | 6 years | 6 years |
Average expected volatility | 75.00% | 74.00% |
Risk-free interest rate | 0.95% | 0.42% |
Weighted average grant date fair value - ($/share) | $ 2.07 | $ 0.79 |
Stock-Based Compensation and _6
Stock-Based Compensation and Other Benefit Plans (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 9 Months Ended |
Mar. 31, 2021 | Sep. 30, 2021 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of Shares Underlying Options, Granted | 401,759 | |
Weighted Average Exercise Price Per Share, Granted | $ 3.14 | |
Stock Options, Monte Carlo [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of Shares Underlying Options, Outstanding, Beginning Balance | 644,000 | |
Number of Shares Underlying Options, Granted | 402,000 | |
Number of Shares Underlying Options, Unvested shares forfeited | (687,000) | |
Number of Shares Underlying Options, Outstanding, Ending Balance | 359,000 | |
Number of Shares Underlying Options, Exercisable | 74,000 | |
Weighted Average Exercise Price Per Share, Beginning Balance | $ 1.23 | |
Weighted Average Exercise Price Per Share, Granted | 3.14 | |
Weighted Average Exercise Price Per Share, Unvested shares forfeited | 1.96 | |
Weighted Average Exercise Price Per Share, Ending Balance | 1.96 | |
Weighted Average Exercise Price Per Share, Exercisable | $ 1.23 | |
Weighted Average Remaining Contractual Term, Outstanding | 9 years | |
Weighted Average Remaining Contractual Term, Exercisable | 8 years 8 months 26 days | |
Aggregate Intrinsic Value, Outstanding | $ 378 | |
Aggregate Intrinsic Value, Exercisable | $ 126 | |
Stock Options, Black-Scholes [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of Shares Underlying Options, Outstanding, Beginning Balance | 1,804,000 | |
Number of Shares Underlying Options, Exercised | (1,088,000) | |
Number of Shares Underlying Options, Unvested shares forfeited | (64,000) | |
Number of Shares Underlying Options, Outstanding, Ending Balance | 652,000 | |
Number of Shares Underlying Options, Exercisable | 555,000 | |
Weighted Average Exercise Price Per Share, Beginning Balance | $ 1.38 | |
Weighted Average Exercise Price Per Share, Exercised | 1.20 | |
Weighted Average Exercise Price Per Share, Unvested shares forfeited | 2.33 | |
Weighted Average Exercise Price Per Share, Ending Balance | 1.60 | |
Weighted Average Exercise Price Per Share, Exercisable | $ 1.47 | |
Weighted Average Remaining Contractual Term, Outstanding | 1 year 8 months 23 days | |
Weighted Average Remaining Contractual Term, Exercisable | 1 year 7 months 9 days | |
Aggregate Intrinsic Value, Outstanding | $ 876 | |
Aggregate Intrinsic Value, Exercisable | $ 816 |
Stock-Based Compensation and _7
Stock-Based Compensation and Other Benefit Plans (Summary of Non Vested Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | |
Sep. 30, 2021 | Sep. 30, 2020 | |
Restricted Stock [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Outstanding, Beginning Balance | 1,155,000 | |
Awards granted | 605,000 | |
Awards vested | (543,000) | |
Unvested awards forfeited | (462,000) | |
Outstanding, Ending Balance | 755,000 | |
Weighted Average Grant Price, Outstanding, Beginning Balance | $ 1.30 | |
Weighted Average Grant Price, Awards granted | 3.13 | |
Weighted Average Grant Price, Awards vested | 1.28 | |
Weighted Average Grant Price, Unvested awards forfeited | 2 | |
Weighted Average Grant Price, Outstanding, Ending Balance | $ 2.36 | |
Stock Appreciation Rights (SARs) [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Outstanding, Beginning Balance | 2,940,000 | |
Awards granted | 0 | 0 |
Awards exercised | (2,306,000) | |
Unvested awards forfeited | (125,000) | |
Outstanding, Ending Balance | 509,000 | |
Outstanding, Exercisable | 338,000 | |
Weighted Average Grant Price, Outstanding, Beginning Balance | $ 1.33 | |
Weighted Average Grant Price, Awards exercised | 1.16 | |
Weighted Average Grant Price, Unvested awards forfeited | 2.33 | |
Weighted Average Grant Price, Outstanding, Ending Balance | 1.83 | |
Weighted Average Exercise Price Per Share, Exercisable | $ 1.69 | |
Term (in years), Outstanding | 2 years 2 months 23 days | |
Term (in years), Exercisable | 2 years 1 month 6 days | |
Aggregate Intrinsic Value, Outstanding | $ 567 | |
Aggregate Intrinsic Value, Exercisable | $ 423 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Income Taxes [Line Items] | ||||
Effective income tax rate | 37.50% | (53.00%) | ||
Change in valuation allowance, discrete item | $ 22,300,000 | $ 22,300,000 | ||
Change in valuation allowance | (15,800,000) | |||
Current tax expense | 5,516,000 | $ 2,393,000 | 15,099,000 | $ 1,876,000 |
Favorable oil price adjustment | 200,000 | 1,700,000 | ||
Current tax expense, net of favorable oil price adjustment | $ 5,300,000 | 13,400,000 | ||
Uncertain tax positions | $ 0 | |||
Authorities Other Than United States And Gabon [Member] | ||||
Income Taxes [Line Items] | ||||
Effective income tax rate | 0.00% |
Income Taxes (Provision for Inc
Income Taxes (Provision for Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Income Taxes [Abstract] | ||||
U.S. Federal: Current | $ 147 | $ (378) | ||
U. S. Federal: Deferred | $ (17,619) | (442) | $ (19,668) | 9,546 |
Foreign: Current | 5,516 | 2,393 | 15,099 | 1,876 |
Foreign: Deferred | (5,080) | (4,857) | (6,703) | 17,426 |
Total income tax expense (benefit) | $ (17,183) | $ (2,759) | $ (11,272) | $ 28,470 |