Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Mar. 03, 2020 | Jun. 28, 2019 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
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, par value $0.10 | ||
Trading Symbol | EGY | ||
Security Exchange Name | NYSE | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 57,978,990 | ||
Entity Central Index Key | 0000894627 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Public Float | $ 97.2 | ||
Documents Incorporated by Reference | Documents incorporated by reference: Portions of the definitive Proxy Statement of VAALCO Energy, Inc. relating to the Annual Meeting of Stockholders to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, which are incorporated into Part III of this Form 10-K. |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 45,917 | $ 33,360 |
Restricted cash | 911 | 804 |
Receivables: | ||
Trade | 14,335 | 11,907 |
Accounts with joint venture owners, net of allowance of $0.5 million for both years | 2,714 | 949 |
Other | 1,517 | 1,398 |
Crude oil inventory | 1,072 | 785 |
Prepayments and other | 3,292 | 6,301 |
Current assets - discontinued operations | 3,290 | |
Total current assets | 69,758 | 58,794 |
Crude oil and natural gas properties and equipment - successful efforts method: | ||
Wells, platforms and other production facilities | 422,651 | 409,487 |
Work-in-progress | 7,378 | 519 |
Undeveloped acreage | 23,771 | 23,771 |
Equipment and other | 11,157 | 9,552 |
Crude oil and natural gas properties, equipment - successful efforts method | 464,957 | 443,329 |
Accumulated depreciation, depletion, amortization and impairment | (396,699) | (390,605) |
Net crude oil and natural gas properties, equipment and other | 68,258 | 52,724 |
Other noncurrent assets: | ||
Restricted cash | 925 | 920 |
Value added tax and other receivables, net of allowance of $1.0 million and $2.0 million, respectively | 3,683 | 2,226 |
Right of use operating lease assets | 33,383 | |
Deferred tax assets | 24,159 | 40,077 |
Abandonment funding | 11,371 | 11,571 |
Total assets | 211,537 | 166,312 |
Current liabilities: | ||
Accounts payable | 15,897 | 8,083 |
Accounts with joint venture owners | 304 | |
Accrued liabilities and other | 29,773 | 14,138 |
Operating lease liabilities - current portion | 11,990 | |
Foreign taxes payable | 5,740 | 3,274 |
Current liabilities - discontinued operations | 350 | 15,245 |
Total current liabilities | 63,750 | 41,044 |
Asset retirement obligations | 15,844 | 14,816 |
Operating lease liabilities - net of current portion | 21,371 | |
Other long term liabilities | 852 | 625 |
Total liabilities | 101,817 | 56,485 |
Commitments and contingencies (Note 12) | ||
Shareholders’ equity: | ||
Preferred stock, $25 par value; 500,000 shares authorized, none issued | ||
Common stock, $0.10 par value; 100,000,000 shares authorized, 67,673,787 and 67,167,994 shares issued, 58,024,571 and 59,595,742 shares outstanding, respectively | 6,767 | 6,717 |
Additional paid-in capital | 73,549 | 72,358 |
Less treasury stock, 9,649,216 and 7,572,251 shares, respectively, at cost | (41,429) | (37,827) |
Retained earnings | 70,833 | 68,579 |
Total shareholders' equity | 109,720 | 109,827 |
Total liabilities and shareholders' equity | $ 211,537 | $ 166,312 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Consolidated Balance Sheets [Abstract] | ||
Allowance for accounts with joint venture owners | $ 0.5 | $ 0.5 |
Allowance for value added tax and other receivables | $ 1 | $ 2 |
Preferred stock, shares authorized | 500,000 | 500,000 |
Preferred stock, par value | $ 25 | $ 25 |
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 | 67,673,787 | 67,167,994 |
Common stock, shares outstanding | 58,024,571 | 59,595,742 |
Treasury stock, shares | 9,649,216 | 7,572,251 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||
Crude oil and natural gas sales | $ 84,521 | $ 104,943 | $ 77,025 |
Operating costs and expenses: | |||
Production expense | 37,689 | 40,415 | 39,697 |
Exploration Expense | 14 | 7 | |
Depreciation, depletion and amortization | 7,083 | 5,596 | 6,457 |
Gain on revision of asset retirement obligations | (379) | (3,325) | |
General and administrative expense | 14,855 | 11,398 | 10,377 |
Bad debt (recovery) expense and other | (341) | (77) | 452 |
Total operating costs and expenses | 58,907 | 54,021 | 56,990 |
Other operating income (expense), net | (4,421) | 365 | (84) |
Operating income | 21,193 | 51,287 | 19,951 |
Other income (expense): | |||
Derivative instruments gain (loss), net | (446) | 4,264 | (1,032) |
Interest income (expense), net | 733 | (145) | (1,414) |
Other, net | (438) | 68 | 3,145 |
Total other income (expense), net | (151) | 4,187 | 699 |
Income from continuing operations before income taxes | 21,042 | 55,474 | 20,650 |
Income tax expense (benefit) | 23,890 | (43,254) | 10,378 |
Income (loss) from continuing operations | (2,848) | 98,728 | 10,272 |
Income (loss) from discontinued operations, net of tax | 5,411 | (496) | (621) |
Net income | $ 2,563 | $ 98,232 | $ 9,651 |
Basic net income (loss) per share: | |||
Income (loss) from continuing operations | $ (0.05) | $ 1.65 | $ 0.17 |
Income (loss) from discontinued operations, net of tax | 0.09 | (0.01) | (0.01) |
Net income per share | $ 0.04 | $ 1.64 | $ 0.16 |
Basic weighted average shares outstanding | 59,143 | 59,248 | 58,717 |
Diluted net income (loss) per share: | |||
Income (loss) from continuing operations | $ (0.05) | $ 1.63 | $ 0.17 |
Income (loss) from discontinued operations, net of tax | 0.09 | (0.01) | (0.01) |
Net income per share | $ 0.04 | $ 1.62 | $ 0.16 |
Diluted weighted average shares outstanding | 59,143 | 59,997 | 58,720 |
Consolidated Statements Of Shar
Consolidated Statements Of Shareholders' Equity (Deficit) - USD ($) $ in Thousands | Common Stock | Treasury Stock | Additional Paid-In Capital | Retained Earnings (Deficit) | Total |
Balance, Treasury Shares | (7,555,000) | ||||
Balance at Dec. 31, 2016 | $ 6,611 | $ (37,933) | $ 70,268 | $ (39,304) | $ (358) |
Balance, Shares at Dec. 31, 2016 | 66,110,000 | ||||
Shares issued - stock-based compensation | $ 33 | 6 | 39 | ||
Shares issued - stock-based compensation, Shares | 334,000 | ||||
Stock-based compensation expense | 977 | 977 | |||
Treasury stock acquired | $ (20) | (20) | |||
Treasury stock acquired, Shares | (26,000) | ||||
Net income | 9,651 | 9,651 | |||
Balance at Dec. 31, 2017 | $ 6,644 | $ (37,953) | 71,251 | (29,653) | 10,289 |
Balance, Shares at Dec. 31, 2017 | 66,444,000 | (7,581,000) | |||
Shares issued - stock-based compensation | $ 73 | $ 177 | 287 | 537 | |
Shares issued - stock-based compensation, Shares | 724,000 | 35,000 | |||
Stock-based compensation expense | 820 | 820 | |||
Treasury stock acquired | $ (51) | (51) | |||
Treasury stock acquired, Shares | (26,000) | ||||
Net income | 98,232 | 98,232 | |||
Balance at Dec. 31, 2018 | $ 6,717 | $ (37,827) | 72,358 | 68,579 | $ 109,827 |
Balance, Shares at Dec. 31, 2018 | 67,168,000 | ||||
Balance, Treasury Shares | (7,572,000) | (7,572,251) | |||
Shares issued - stock-based compensation | $ 50 | 206 | $ 256 | ||
Shares issued - stock-based compensation, Shares | 506,000 | (10,000) | |||
Stock-based compensation expense | 985 | 985 | |||
Treasury stock acquired | $ (3,602) | (309) | (3,911) | ||
Treasury stock acquired, Shares | (2,067,000) | ||||
Net income | 2,563 | 2,563 | |||
Balance at Dec. 31, 2019 | $ 6,767 | $ (41,429) | $ 73,549 | $ 70,833 | $ 109,720 |
Balance, Shares at Dec. 31, 2019 | 67,674,000 | ||||
Balance, Treasury Shares | (9,649,000) | (9,649,216) |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income | $ 2,563 | $ 98,232 | $ 9,651 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
(Income) loss from discontinued operations | (5,411) | 496 | 621 |
Depreciation, depletion and amortization | 7,083 | 5,596 | 6,457 |
Gain on revision of asset retirement obligations | (379) | (3,325) | |
Other amortization | 241 | 417 | 369 |
Deferred taxes | 14,480 | (56,907) | (1,260) |
Unrealized foreign exchange (gain) loss | (50) | 834 | (576) |
Stock-based compensation | 3,506 | 2,388 | 1,098 |
Cash settlements paid on exercised stock appreciation rights | (491) | (82) | |
Derivative instruments (gain) loss | 446 | (4,264) | 1,032 |
Cash settlements received on matured derivative contracts, net | 2,439 | 744 | 195 |
Bad debt (recovery) expense and other | (341) | (77) | 452 |
Other operating (income) loss, net | 58 | (570) | 84 |
Operational expenses associated with equipment and other | 69 | 1,604 | 1,189 |
Change in operating assets and liabilities: | |||
Trade receivables | (2,428) | (8,351) | 3,195 |
Accounts with joint venture owners | (2,075) | 2,747 | (108) |
Other receivables | (94) | (1,330) | (43) |
Crude oil inventory | (287) | 2,478 | (2,350) |
Prepayments and other | (1,014) | 1,164 | 1,646 |
Value added tax and other receivables | 275 | (777) | (3,025) |
Accounts payable | 6,011 | (3,409) | (7,297) |
Foreign taxes payable | 2,396 | 2,751 | |
Accrued liabilities and other | 4,161 | (2,131) | 2,050 |
Net cash provided by continuing operating activities | 31,158 | 38,228 | 13,380 |
Net cash used in discontinued operating activities | (4,686) | (1,052) | (4,423) |
Net cash provided by operating activities | 26,472 | 37,176 | 8,957 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Acquisitions | 64 | ||
Proceeds from sale of crude oil and natural gas properties | 250 | ||
Property and equipment expenditures | (10,348) | (14,127) | (1,813) |
Net cash used in continuing investing activities | (10,348) | (14,127) | (1,499) |
Net cash used in discontinued investing activities | |||
Net cash used in investing activities | (10,348) | (14,127) | (1,499) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from the issuances of common stock | 256 | 544 | 39 |
Treasury shares | (3,911) | (58) | (20) |
Borrowings | 4,167 | ||
Debt repayment | (9,166) | (10,001) | |
Net cash used in continuing financing activities | (3,655) | (8,680) | (5,815) |
Net cash used in discontinued financing activities | |||
Net cash used in financing activities | (3,655) | (8,680) | (5,815) |
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | 12,469 | 14,369 | 1,643 |
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF YEAR | 46,655 | 32,286 | 30,643 |
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF YEAR | 59,124 | 46,655 | 32,286 |
Supplemental disclosure of cash flow information: | |||
Interest paid in cash | 257 | 997 | |
Income taxes (received) paid in cash | (674) | 2,720 | 15,153 |
Income taxes paid in-kind with crude oil | 7,268 | 9,385 | |
Supplemental disclosure of non-cash investing and financing activities: | |||
Property and equipment additions incurred but not paid at end of period | 13,646 | 2,138 | 455 |
Crude oil and natural gas property additions paid with non-cash assets | 4,197 | ||
Gross-up of crude oil and natural gas properties by establishment of deferred tax liability | 18,613 | ||
Recognition of right-of-use operating lease assets | 44,681 | ||
Recognition of right-of-use operating lease liabilities | 44,656 | ||
Asset retirement obligations | 595 | (6,527) | $ 600 |
Restricted stock issued out of treasury | $ 309 | $ 177 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2019 | |
Organization [Abstract] | |
Organization | 1. ORGANIZATION 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 has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 4 below, VAALCO has discontinued operations associated with activities in Angola, West Africa. The Company’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO International, Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Organization [Abstract] | |
Summary Of Significant Accounting Policies | 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation. Reclassifications – Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the presentation of stock based compensation and derivatives on the Company’s consolidated statements of cash flows. These reclassifications had no material impact on the Company’s financial position or results of operations. Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the United States (“U.S.”) (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. Estimates of crude oil and natural gas reserves used to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available. Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at December 31, 2019 and 2018 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at December 31, 2019 and 2018 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 12. 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 consolidated balance sheets to the amounts shown in the consolidated statement of cash flows. December 31, 2019 2018 (in thousands) Cash and cash equivalents $ 45,917 $ 33,360 Restricted cash - current 911 804 Restricted cash - non-current 925 920 Abandonment funding 11,371 11,571 Total cash, cash equivalents and restricted cash $ 59,124 $ 46,655 The Company conducts regular abandonment studies 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” on the 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 11 for further discussion. On February 28, 2019, the Gabonese branch of the 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 for African Economic and Monetary Community (“ 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 Etame PSC provides these payments must be denominated in U.S. dollars and the CEMAC regulations provide for establishment of a U.S. dollar account with the Central Bank. Although we have requested establishment of such account, the Central Bank has not complied with our requests. As a result, we were not able to make the annual abandonment funding payment in 2019. Amendment No. 5 to the Etame PSC also provides that in the event that the Gabonese bank fails for any reasons to reimburse all of the principal and interest due, the Contractor shall no longer be held liable for the obligation to remediate the sites. Accounts with joint owners – Accounts with joint owners represent the excess of charges billed over cash calls paid by the joint owners for exploration, development and production expenditures made by the Company as an operator. Bad debts – Quarterly, the Company evaluates its accounts receivable balances to confirm collectability. 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 consolidated statements of operations. The majority of the accounts receivable balances are with the Company’s joint venture owners, purchasers of the production and 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 costs in Gabon (including the VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). As of December 31, 2019, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF 5.4 billion (XAF 1.8 billion, net to VAALCO). The VAT receivable balance was reduced by XAF 14.1 billion (XAF 4.7 billion, net to VAALCO or $ 4.2 million) associated with a signing bonus as part of the Sixth Amendment to the Etame PSC executed on September 17, 2018 (“PSC Extension”). As of December 31, 2019, the exchange rate was XAF 585.7 = $1.00. In 2019, 2018 and 2017, the Company recorded recoveries (allowances) of $ 0.3 million, $ 0.1 million and $( 0.4 ) million, respectively, related to VAT, which the government of Gabon has not reimbursed. 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 consolidated balance sheets. Because both the VAT receivable and the related allowance 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 profit/loss. Such foreign currency gains/(losses) are reported separately in the “Other, net” line item of the consolidated statements of operations. The following table provides an analysis of the change in the allowance: Years Ended December 31, 2019 2018 2017 (in thousands) Allowance for bad debt Balance at beginning of year $ ( 2,535 ) $ ( 7,033 ) $ ( 5,211 ) Bad debt recovery (charge) 341 77 ( 452 ) Reclassification to leasehold costs related to signing bonus — 4,197 — Reclassification of Sojitz acquisition — — ( 694 ) Adjustment associated with settlement of customs audit 623 — — Foreign currency gain 63 224 ( 676 ) Balance at end of period $ ( 1,508 ) $ ( 2,535 ) $ ( 7,033 ) Crude oil inventory – Crude oil inventories are carried at the lower of cost or market and represent the share of crude oil produced and stored on the FPSO, but unsold at the end of the period. Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the consolidated balance sheet, are primarily used for production related activities. These assets are valued at the lower of cost, determined by the weighted-average method, or market. 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. Capitalizati on – 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 (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a field-by-field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field-by-field 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. Impairment – The Company reviews the crude oil and natural gas producing properties for impairment on a field-by-field 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 a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. 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. The Company recorded no material adjustments for inventory obsolescence for the years 2019 or 2017. The Company identified equipment inventory in Gabon that required an adjustment of $ 0.4 million to the “Other operating income (expense), net” line item of the consolidated statement of operations for the year ended December 31, 2018. 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. Capitalized interest – Interest costs and commitment fees from external borrowings are capitalized on exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets . The Company capitalized no interest costs during the years ended December 31, 2019, 2018 and 2017. Lease commitments – The Company lessees of office buildings, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and are expensed either as production expenses or general and administrative expenses. See Note 13 for further discussion. Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil and natural gas properties. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of 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, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note 11 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. During the year ended December 31, 2018, the Company recorded a downward revision of $ 6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9. In the second half of 2019, the Company recorded $ 0.6 million in additions associated with the spudding of the Etame 9H and Etame 11H development wells at the Etame field in conjunction with commencement of its 2019/2020 drilling campaign and $ 0.4 million downward revision associated with the Mutamba Iroru block onshore Gabon. Revenue recognition – Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame PSC is not a customer contract. The terms of the Etame 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” 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 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 7 for further discussion. Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs. Stock-based compensation – The Company measured 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. Grant date fair value for options is estimated using the Black-Scholes option pricing model. The model employs various 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 option award . For restricted stock, grant date fair value is determined using the market value of the common stock on the date of grant. The fair value of stock appreciation rights (“SARs”) is based on a Monte Carlo simulation at grant date and at each subsequent reporting date for the 2016 grants. The Monte Carlo simulation to value the SARs uses 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 SARs, (v) the expected dividend yield is based on the anticipated dividend payments, (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 SARs. The Company utilizes the Black-Scholes option pricing model to measure the fair value of the 2019, 2018 and 2017 SARs. The stock-based compensation expense is recognized based on the awards as they vest, using the straight-line attribution method over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. When awards are forfeited before they vest, previously recognized expense related to such forfeitures is reversed in the period in which the forfeiture occurs. See Note 17 for further discussion. Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries . Gains and losses on foreign currency transactions are included in income. Within the consolidated statements of operations line item “Other income (expense)—Other, net,” the Company recognized losses on foreign currency transactions of $ 0.2 million and $ 0.1 million in 2019 and 2018, respectively, while the Company recognized gains on foreign currency transactions of $ 0.5 million 2017. Income taxes – The annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual 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 level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the 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. We also record as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil which results due to change in value from the time the allocation is originally produced to the time the allocation is actually lifted. Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-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 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 expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the consolidated financial position and results of operations. See Note 8 for further discussion. Derivative instruments and hedging activities – The Company uses derivative financial instruments to achieve a more predictable cash flow from crude oil production by reducing the exposure to price fluctuations. All of the crude oil put contracts, which provided for settlement based upon reported the Brent price, had expired as of December 31, 2017. The Company’s derivative instruments at December 31, 2018, consisted of crude oil swaps, which require the Company to pay a counterparty when the price of crude oil exceeds $ 74.00 per barrel, and where the price of crude oil falls below $ 74.00 , the Company received a payment from the counterparty. On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average of $ 66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. See Note 10 for further discussion. The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments (gain) loss, net” and “Cash settlements received on matured derivative contracts, net” lines items located as adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities on the statements of consolidated cash flows. The Company received net cash settlements of $ 2.4 million, $ 0.7 million and $ 0.2 million during the years ended December 31, 2019, 2018 and 2017, respectively, related to matured derivative contracts. Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the internally developed present value of future cash flows model that underlies the fair-value measurement). Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for SARs and guarantee. As discussed further in Note 10, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivative asset commodity swaps referenced below are reported on the consolidated balance sheet on line item “ Prepayments and other.” SARs liabilities are measured and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported on the consolidated balance sheet on line item “Accrued liabilities and other” while the long-term portion is located on the line item “Other long term liabilities”. With respect to the other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. As of December 31, 2019 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 636 $ — $ 636 $ — $ 636 $ — $ 636 Liabilities SARs liability Accrued liabilities $ — $ 2,638 $ — $ 2,638 SARs liability Other long-term liabilities — 852 — 852 $ — $ 3,490 $ — $ 3,490 As of December 31, 2018 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 Liabilities SARs liability Accrued liabilities $ — $ 1,007 $ — $ 1,007 SARs liability Other long-term liabilities — 625 — 625 $ — $ 1,632 $ — $ 1,632 Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above. In addition, “Other, net” for the year ended December 31, 2017 includes $ 2.6 million related to the reversal of accruals for liabilities the Company was no longer obligated to pay. |
New Accounting Standards
New Accounting Standards | 12 Months Ended |
Dec. 31, 2019 | |
New Accounting Standards [Abstract] | |
New Accounting Standards | 3 . NEW ACCOUNTING STANDARDS Not Yet 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 Company is currently evaluating this guidance to determine the impact it may have on its consolidated financial statements. In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other, in making the determination as to which implementation costs are to be capitalized as assets and which costs are to be expensed as incurred. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, and an entity can elect to apply the new guidance on a prospective or retrospective basis. The Company does not expect a material impact of adopting this guidance on the Company’s financial position, results of operations, cash flows and related disclosures upon adoption on January 1, 2020 . In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This ASU modifies the disclosure requirements for fair value measurements. ASU 2018-13 removes the requirement to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of changes in unrealized gains and losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 applies to all entities and is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. The Company does not expect a material impact of adopting this guidance on the Company’s financial position, results of operations and cash flows; however, the Company does expect an expansion to its current disclosures upon adoption on January 1, 2020 . In June 2016, the FASB issued 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 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 February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), which amends the accounting standards for leases. This accounting standard w as further clarified by ASU 2018-10, Codification Improvements to Topic 842 and ASU 2018-11, Leases: Targeted Improvements, both of which were issued in July 2018 together (“Topic 842”). Topic 842 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases previously classified as operating leases on the balance sheet under ASC 840 - Leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance under ASC 840 - Leases. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. In transition, lessees and lessors may use either a prospective approach in which they recognize and measure leases at the date of adoption and recognize a cumulative effect adjustment to the opening balance of retained earnings or they may use a modified retrospective approach in which leases are recognized and measured at the beginning of the earliest period presented. T he Company used the prospective approach with adoption of the new standard effective January 1, 2019. Leases with terms greater than 12 months, which were previously treated as operating leases, have been capitalized. The adoption of this standard resulted in the recording of a right of use (“ROU”) asset related to certain of the Company’s operating leases with a corresponding lease liability. This resulted in a significant increase in total assets and liabilities and a decrease in working capital. In connection with the Company’s implementation plan, the Company reviewed its lease contracts and evaluated other contracts to identify embedded leases to determine the appropriate accounting treatment. The new leasing standard requires capitalization based on the expected term of the lease that may or may not extend beyond the minimum period. The most significant lease the Company currently has is related to the FPSO. As of January 1, 2019, for operating leases under which the Company is the lessee, the Company recorded a non - cash adjustment of $ 38.9 million in “Right of use operating lease assets” to recognize an aggregate ROU asset, and the Company recorded a corresponding $ 10.2 million and $ 28.7 million in “Operating lease liabilities” and “Long-term operating lease liabilities,” respectively, for the aggregate operating lease liability. The Company has accounted for lease and non - lease components of its operating leases separately. The Company has not recognized ROU assets or lease liabilities for its short - term leases. The Company’s adoption did not have and is not expected in the future to have a material effect on the Company’s consolidated statements of operations or cash flows. See Note 13 for further discussion. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Beginning January 1, 2018, the Company adopted ASU No. 2014-09, and the related additional guidance provided under ASU No. 2016-10, 2016-11 and 2016-12 (together with ASU 2014-09, “Revenue Recognition ASU”). This new standard replaced most existing revenue recognition guidance in U.S. GAAP. The core principle of the Revenue Recognition ASU requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. The Company adopted the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedient that states 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. This standard applies to revenues from contracts with customers. In addition, the Company recognizes other items from carried interest recoupment and royalties paid that are reported in revenues but are not considered to be revenues from contracts with customers. For revenues from contracts with customers, adoption of this standard did not result in a change in the timing or amount of revenue recognized, and therefore the adoption of this standard did not have a material impact on the financial position, results of operations, debt covenants or business practices. The adoption did result in expanded disclosures related to the nature of the sales contracts and other matters related to revenues and the accounting for revenues, which are reflected in Note 7. |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2019 | |
Dispositions [Abstract] | |
Dispositions | 4. DISPOSITIONS Sale of Certain U.S. Properties In April 2017, the Company completed the sale of the Company’s interests in the East Poplar Dome field in Montana for $ 0.3 million, resulting in a gain of approximately $ 0.3 million reported on the line “Other operating income (expense), net” in the results of operations for the year ended December 31, 2017. Discontinued Operations - Angola In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“PSA”). The working interest is 40 %, and the Company carries Sonangol P&P for 10 % of the work program. On September 30, 2016, the Company notified Sonangol P&P that the Company 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 the Company was withdrawing from the PSA. Further to the decision to withdraw from Angola, the Company has taken actions to close the office in Angola and reduce future 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 consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the 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 consolidated statements of cash flows. The following tables summarize selected financial information related to the Angola segment assets and liabilities as of December 31, 2019 and 2018 and its results of operations for the years ended December 31, 2019, 2018 and 2017. Summarized Results of Discontinued Operations Years Ended December 31, 2019 2018 2017 (in thousands) Operating costs and expenses: Gain on settlement of drilling obligation $ ( 7,193 ) $ — $ — General and administrative expense 344 467 615 Total operating costs, expenses and (recovery) ( 6,849 ) 467 615 Operating income (loss) 6,849 ( 467 ) ( 615 ) Other income (expense): Other, net — ( 29 ) ( 3 ) Total other income (expense) — ( 29 ) ( 3 ) Income (loss) from discontinued operations before income taxes 6,849 ( 496 ) ( 618 ) Income tax expense 1,438 — 3 Income (loss) from discontinued operations $ 5,411 $ ( 496 ) $ ( 621 ) Assets and Liabilities Attributable to Discontinued Operations December 31, 2019 2018 (in thousands) ASSETS Accounts with joint venture owners $ — $ 3,290 Total current assets — 3,290 Total assets $ — $ 3,290 LIABILITIES Current liabilities: Accounts payable $ 8 $ 73 Accrued liabilities and other 342 15,172 Total current liabilities 350 15,245 Total liabilities $ 350 $ 15,245 Drilling Obligation Under the Block 5 PSA, the Company and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the Block 5 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA provided for a stipulated payment of $ 10.0 million for each of the three exploration wells that a drilling obligation remained under the terms of the Block 5 PSA, of which the Company’s participating interest share would be $ 5.0 million per well. The Company reflected an accrual of $ 15.0 million for a potential payment as of December 31, 2018. In the first quarter of 2019, the Company and Sonangol E.P. entered into a settlement agreement finalizing the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola. Pursuant to the settlement agreement, the Company agreed to pay $ 4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the $ 3.3 million receivable from Sonangol P&P. The receivable was related to joint interest billings and was reflected as a current asset from discontinued operations at year-end 2018. As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $ 5.7 million in the first quarter of 2019. In July 2019, subsequent to the publication of an executive decree from the Ministry of Mineral Resources and Petroleum, the Company paid the $ 4.5 million due under the settlement agreement. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment Information [Abstract] | |
Segment Information | 5. SEGMENT INFORMATION The Company’s operations are based in Gabon and Equatorial Guinea. Each of the two reportable operating segments is organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker, and m anagement 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 years ended December 31, 2019, 2018 and 2017 and long-lived assets and segment assets at December 31, 2019 and 2018 are as follows: Years Ended December 31, 2019 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 84,521 $ — $ — $ 84,521 Depreciation, depletion and amortization 6,825 — 258 7,083 Gain on revision of asset retirement obligations ( 379 ) — — ( 379 ) Bad debt recovery and other ( 341 ) — — ( 341 ) Other operating income (expense), net ( 4,456 ) — 35 ( 4,421 ) Operating income (loss) 35,049 ( 438 ) ( 13,418 ) 21,193 Derivatives instruments loss, net — — ( 446 ) ( 446 ) Interest income 5 — 728 733 Other, net ( 230 ) ( 3 ) ( 205 ) ( 438 ) Income tax expense 20,311 12 3,567 23,890 Additions to crude oil and natural gas properties and equipment – accrual 22,116 — 57 22,173 Years Ended December 31, 2018 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 104,938 $ — $ 5 $ 104,943 Depreciation, depletion and amortization 5,176 — 420 5,596 Gain on revision of asset retirement obligations ( 3,325 ) — — ( 3,325 ) Bad debt recovery and other ( 77 ) — — ( 77 ) Other operating income, net 365 — — 365 Operating income (loss) 61,930 ( 470 ) ( 10,173 ) 51,287 Derivatives instruments gain, net — — 4,264 4,264 Interest income (expense), net ( 396 ) — 251 ( 145 ) Other, net 92 ( 4 ) ( 20 ) 68 Income tax benefit ( 26,670 ) — ( 16,584 ) ( 43,254 ) Additions to crude oil and natural gas properties and equipment – accrual 38,430 187 17 38,634 Years Ended December 31, 2017 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 76,978 $ — $ 47 $ 77,025 Depreciation, depletion and amortization 6,196 — 261 6,457 Bad debt expense and other 452 — — 452 Other operating expense, net ( 84 ) — — ( 84 ) Operating income (loss) 28,488 ( 122 ) ( 8,415 ) 19,951 Derivatives instruments loss, net — — ( 1,032 ) ( 1,032 ) Interest expense, net ( 1,414 ) — — ( 1,414 ) Other, net 3,142 15 ( 12 ) 3,145 Income tax expense 11,638 — ( 1,260 ) 10,378 Additions to crude oil and natural gas properties and equipment – accrual 1,576 — 126 1,702 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Long-lived assets from continuing operations: As of December 31, 2019 $ 57,930 $ 10,000 $ 328 $ 68,258 As of December 31, 2018 $ 42,195 $ 10,187 $ 342 52,724 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Total assets from continuing operations: As of December 31, 2019 $ 151,686 $ 10,087 $ 49,764 $ 211,537 As of December 31, 2018 $ 103,401 $ 10,320 $ 49,301 163,022 Information about the Company’s most significant customers The Company 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 August 2015 through January 2019, the Company sold its crude oil to Glencore Energy UK Ltd. (“Glencore”). The Company signed a new contract with Mercuria Energy Trading SA (“Mercuria”) that covers sales from February 2019 through January 2020 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The Company signed a new contract with ExxonMobil Corporation (“Exxon”) that covers sales from February 2020 through January 2021 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. Sales of crude oil to Glencore and Mercuria were approximately 6 % and 94 %, respectively, of total revenues for the period during the terms of their contracts. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 6. 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 : Years Ended December 31, 2019 2018 2017 (in thousands) Net income (loss) (numerator): Income (loss) from continuing operations $ ( 2,848 ) $ 98,728 $ 10,272 (Income) loss from continuing operations attributable to unvested shares 21 ( 1,231 ) ( 62 ) Numerator for basic ( 2,827 ) 97,497 10,210 Loss from continuing operations attributable to unvested shares ( 21 ) — — Numerator for dilutive $ ( 2,848 ) $ 97,497 $ 10,210 Income (loss) from discontinued operations, net of tax $ 5,411 $ ( 496 ) $ ( 621 ) (Income) loss from discontinued operations attributable to unvested shares ( 39 ) 6 4 Numerator for basic 5,372 ( 490 ) ( 617 ) Income from discontinued operations attributable to unvested shares 39 — — Numerator for dilutive $ 5,411 $ ( 490 ) $ ( 617 ) Net income $ 2,563 $ 98,232 $ 9,651 Net income attributable to unvested shares ( 18 ) ( 1,225 ) ( 58 ) Numerator for basic 2,545 97,007 9,593 Net income attributable to unvested shares 18 — — Numerator for dilutive $ 2,563 $ 97,007 $ 9,593 Weighted average shares (denominator): Basic weighted average shares outstanding 59,143 59,248 58,717 Effect of dilutive securities — 749 3 Diluted weighted average shares outstanding 59,143 59,997 58,720 Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive 603 1,316 2,823 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2019 | |
Revenue [Abstract] | |
Revenue | 7. REVENUE Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPAs”). The COSPAs have been and will be renewed or replaced from time to time either with the current buyer or another buyer. Since August 2015, a COSPA has been in place with the same customer, initially for a one-year period, with amendments that extended the period through January 31, 2018. On February 1, 2018, a new COSPA was entered into with this same customer, which terminated January 31, 2019. A COSPA with a different customer was executed for the period from February 2019 through January 2020. A new COSPA with a different customer has been executed for the period from February 2020 through January 2021. 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. Previously, the Company followed the sales method of accounting to account for crude oil production imbalances. In conjunction with the adoption of ASC Topic 606 on January 1, 2018, the Company will continue to account 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 thirty days after the date of the bill of lading. For each lifting of crude oil, the price is determined based on a formula using published Dated Brent prices as well as market differentials plus a fixed contract differential. 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 PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame 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” 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 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 PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Prior to February 1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1, 2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in 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. The in-kind payment related to the September 2018 lifting was $ 9.4 million. The in-kind payment related to the April 2019 lifting was $ 7.3 million. As of December 31, 2019, the foreign taxes payable attributable to this obligation is $ 5.7 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 PSC: Years Ended December 31, 2019 2018 2017 Revenue from customer contracts: (in thousands) Sales under the COSPA $ 86,554 $ 104,891 $ 74,693 Gabonese government share of Profit Oil — 2,193 11,638 U.S. crude oil and natural gas revenue — 5 47 Other items reported in revenue not associated with customer contracts: Gabonese government share of Profit Oil taken in-kind 7,268 9,385 — Carried interest recoupment 2,950 3,545 2,205 Royalties ( 12,251 ) ( 15,076 ) ( 11,558 ) Total revenue, net $ 84,521 $ 104,943 $ 77,025 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Taxes [Abstract] | |
Income Taxes | 8. INCOME TAXES VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes. On December 22, 2017, the U. S. government enacted the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act included significant changes to the U.S. income tax system including but not limited to: a federal corporate rate reduction from 35 % to 21 %; limitations on the deductibility of interest expense and executive compensation; repeal of the Alternative Minimum Tax (“AMT”); full expensing provisions related to business assets; creation of new minimum taxes such as the base erosion anti-abuse tax (“BEAT”) and Global Intangible Low Taxed Income (“GILTI”) tax; and the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system, which resulted in a one time U.S. tax liability on those earnings that had not previously been repatriated to the U.S. (the “Transition Tax”). The Company has appropriately accounted for the Tax Reform Act provisions in its financial statements. However, the Company continues to monitor new regulations and legislation that has resulted due to the Tax Reform Act and will further analyze the implications as they arise. Income taxes attributable to continuing operations for the years ended December 31, 2019, 2018, and 2017 are attributable to foreign taxes payable in Gabon as well as income taxes in the U.S. Provision for income taxes related to income (loss) from continuing operations consists of the following: Years Ended December 31, 2019 2018 2017 U.S. Federal: (in thousands) Current $ ( 337 ) $ ( 674 ) $ — Deferred 3,916 ( 15,910 ) ( 1,260 ) Foreign: Current 9,747 14,327 11,638 Deferred 10,564 ( 40,997 ) — Total $ 23,890 $ ( 43,254 ) $ 10,378 As of December 31, 2019 and 2018, the Company had deferred tax assets of $ 108.8 million and $ 131.0 million, respectively primarily attributable to U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions. In assessing the realizability of the deferred tax assets, the Company considers all available positive and negative evidence, and the Company makes a determination whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. Numerous judgments and assumptions are inherent in this assessment including the determination of future taxable income, which is affected by a number of factors, including future operating conditions (particularly as related to prevailing crude oil prices) and changing tax laws. As of December 31, 2019 and 2018, the Company anticipated it will only be able to partially utilize its deferred tax assets. On the basis of this evaluation, a valuation allowance of $ 84.6 million and $ 90.9 million were recorded as of December 31, 2019 and 2018, respectively. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized. Taxes paid in Gabon with respect to earnings from the Etame Marin block are determined under the provisions of the Etame PSC. In accordance with the Etame 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. For each calendar year, the Consortium is entitled to receive a percentage of the production (“Cost Recovery Percentage”) remaining after deducting royalties so long as there are amounts remaining in the Cost Account. Prior to the PSC Extension, the Cost Recovery Percentage was 70 %. As a result of the PSC Extension, the Cost Recovery Percentage has been increased to 80 % for the period from September 17, 2018 through September 16, 2028. See Note 9 for further discussion of the PSC Extension. After September 16, 2028, the Cost Recovery Percentage returns to 70 %. The difference between revenues, net of royalties, and the costs recovered for the period is “Profit Oil.” As payment of corporate income taxes, the Consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from 50 % to 60 %. The percentage of Profit Oil paid to the government as tax is a function of production rates. When the Cost Account is less than the entitled recovery percentage (either 70 % or 80 %, depending on the period), Profit Oil as a percentage of revenues increases and Gabon taxes paid increase as a percentage of revenues. We also record as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil which results due to change in value from the time the allocation is originally produced to the time the allocation is actually lifted. Prior to the PSC Extension, the Cost Recovery Percentage was 70 %, and the exploitation periods ended beginning in June 2021. Future proved reserves did not extend beyond 2021. Opportunities for increasing reserves by drilling wells were limited, and while oil prices had improved since 2016, they were not at the levels needed to recover VAALCO’s Cost Account. As a result of these factors, the ability to recognize the benefit from the potential deferred tax asset related to the difference between VAALCO’s Cost Account and the book basis of the Etame Marin block assets was deemed to be remote, and the deferred tax asset was not recognized. As a result of the PSC Extension in September 2018, the Cost Recovery Percentage increased to 80 % and the exploitation periods were extended to at least September 16, 2028, and if the two five-year option periods are elected, the period would extend to September 16, 2038. In addition to the benefits under the PSC Extension, the Company expected higher future crude oil prices based on current Brent futures strip pricing over the next few years, and the Company expects future production from the drilling of two wells in 2019. Expectations related to future crude oil prices, drilling activities and other factors are evaluated quarterly in order to estimate the future taxable income which is considered in the evidence used to determine the realizability of deferred tax assets. The primary differences between the financial statement and tax bases of assets and liabilities resulted in deferred tax assets associated with continuing operations at December 31, 2019 and 2018 are as follows: As of December 31, (in thousands) 2019 2018 Deferred tax assets: Basis difference in fixed assets $ 26,590 $ 38,479 Foreign tax credit carryforward 34,144 43,760 Alternative minimum tax credit carryover 337 674 U.S. federal net operating losses 30,572 20,616 Foreign net operating losses 11,770 19,989 Asset retirement obligations 3,407 3,111 Basis difference in accrued liabilities 676 3,816 Basis difference in receivables 171 387 Other 1,120 180 Total deferred tax assets 108,787 131,012 Valuation allowance ( 84,628 ) ( 90,935 ) Net deferred tax assets $ 24,159 $ 40,077 Foreign tax credits will expire between the years 2020 and 2025 . Foreign tax credits of $ 9.6 million expired during the year. The alternative minimum tax credits do not expire, and foreign net operating losses (“NOLs”) are not subject to expiry dates. The NOLs for the Gabon subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues. The Company liquidated the United Kingdom subsidiary and plans to liquidate the Gabon branch associated with its Mutamba operations, both of which carried NOLs. Accordingly, the related deferred tax assets of $ 8.7 million and $ 15.9 million, respectively, were written off in 2018 with a corresponding offset to the valuation allowance. All of the Company’s U.S. federal NOLs that were incurred prior to 2018 will expire between 2035 and 2037 . U.S. federal NOLs incurred after 2017 do not expire. The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code. In assessing the realizability of the deferred tax assets, we consider all available positive and negative evidence in determining whether it is more likely than not that some or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in this assessment including the determination of future taxable income, which is affected by a number of factors including future operating conditions (particularly as related to prevailing crude oil prices) and changing tax laws. The Company does not anticipate utilization of the foreign tax credits prior to expiration and have recorded a full valuation allowance on these deferred tax assets. As a result of the 2017 tax legislation enacted in the U.S., the Company expects to realize the benefit from the AMT credit carryforwards. The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit. The Company believes that its income tax positions and deductions will be sustained on audit and therefore no reserves for uncertain tax positions have been established. Accordingly, no interest or penalties have been accrued as of December 31, 2019 and 2018. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense. Income (loss) from continuing operations before income taxes is attributable as follows: Year Ended December 31, (in thousands) 2019 2018 2017 U.S. $ ( 13,330 ) $ ( 5,672 ) $ ( 9,453 ) Foreign 34,372 61,146 30,103 $ 21,042 $ 55,474 $ 20,650 The reconciliation of income tax expense (benefit) attributable to income (loss) from continuing operations to income tax on income (loss) from continuing operations at the U.S. statutory rate is as follows: Year Ended December 31, (in thousands) 2019 2018 2017 Tax provision computed at U.S. statutory rate $ 4,386 $ 11,650 $ 7,228 Foreign taxes not offset in U.S. by foreign tax credits 16,015 24,840 6,775 Impact of Tax Reform Act — — 52,449 Recognition of foreign deferred tax assets, net of U.S. impact — ( 45,751 ) — Unrealizable foreign deferred tax assets — 24,176 — Effect of change in foreign statutory rates — — — Permanent differences 180 ( 104 ) 309 Foreign tax credit expirations 9,616 4,311 2,394 Increase/(decrease) in valuation allowance ( 6,307 ) ( 62,270 ) ( 58,777 ) Other — ( 106 ) — Total income tax expense (benefit) $ 23,890 $ ( 43,254 ) $ 10,378 For the years ended December 31, 2019, 2018 and 2017, the Company is subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions: Jurisdiction Years U.S. 2009 -2019 Gabon 2015 -2019 |
Crude Oil and Natural Gas Prope
Crude Oil and Natural Gas Properties and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Crude Oil and Natural Gas Properties and Equipment [Abstract] | |
Crude Oil and Natural Gas Properties and Equipment | 9. CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT Extension of Term of Etame Marin Block PSC On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “Consortium”) received an implementing Presidential Decree from the government of Gabon authorizing the PSC Extension. The Company’s subsidiary, VAALCO Gabon S.A., has a 33.575 % participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block. The PSC Extension extends 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. Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would expire beginning in June 2021. The PSC Extension also grants 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) is to be paid in cash by the Consortium following the end of the drilling activities described below. The Company has accrued the $ 1.7 million share of this remaining payment as of December 31, 2019. This payment was made in February 2020. The amount paid through a reduction in VAT has been recorded at $ 4.2 million, which represents the book value of the receivable, net of the valuation allowance as of the effective date. In addition, the Company recorded an increase of $ 18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis. A corresponding $ 18.6 million deferred tax liability was recorded, which reduced the net deferred tax assets. The Company has allocated the share of the signing bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $ 22.5 million being attributed to proved leasehold costs and $ 13.7 million attributed to unproved leasehold costs. Under the PSC Extension, by September 16, 2020, the Consortium is required to drill two wells and two appraisal wellbores. If the wells are not drilled, then the Consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon. The Consortium completed drilling one development well and one appraisal wellbore during the second half of 2019 and completed the remaining development well and appraisal wellbore during the first quarter 2020. The Consortium is also required to complete two technical studies by September 16, 2020 at an estimated cost of $ 1.3 million gross ($ 0.4 million, net to VAALCO). These studies are currently being performed. Prior to the PSC Extension, the Consortium was entitled to take up to 70 % of production remaining after the 13 % royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account. Under the PSC Extension, the Cost Recovery Percentage is 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 %. Prior to the PSC Extension, the PSC provided for the government of Gabon to take a 7.5 % gross working interest carried by the Consortium. The government of Gabon transferred this interest to a third party. Pursuant to the PSC Extension, 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 0.8 %. 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 year ended December 31, 2019 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired . During the year ended December 31, 2018, crude oil and natural gas property costs increased significantly as a result of amounts recorded in connection with the PSC Extension and year-end crude oil prices decreased over the prior year; however, reserves increased significantly over the prior year. The Company evaluated these and other factors and determined that no impairment was required for any of the Etame fields. There was no triggering event in the year ended December 31, 2017 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired . Undeveloped Leasehold Costs The Company has a 31 % working interest in an undeveloped portion of Block P offshore Equatorial Guinea that the Company acquired in 2012 for which the Company has $ 10.0 million capitalized in undeveloped acreage. For a number of years, the Block P interest was in suspension; however, in September 2018, the Ministry of Mines and Hydrocarbons (“EG MMH”) lifted the suspension. The EG MMH approved our appointment as operator for Block P on November 12, 2019 and the Company is currently waiting on a production sharing contract amendment to begin activities in Block P. VAALCO intends to seek a joint venture owner on a promoted basis that will cover all or substantially all of the cost to drill an exploratory well. If VAALCO fails to meet the defined commitments when the new PSC amendment terms are agreed, the capitalized costs associated with Block P would be impaired. As of December 31, 2019, the Company had $ 10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The production sharing contract covering this development and production area 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, the exploitation area was expanded to include previously undeveloped acreage. The Company allocated $ 6.7 million of the share of the signing bonus and $ 7.1 million of the $ 18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame PSC. Capitalized Equipment Inventory Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded on “Other operating loss, net” line item of the consolidated statement of operations, but were not material for the years ended December 31, 2019, 2018 and 2017. |
Derivatives and Fair Value
Derivatives and Fair Value | 12 Months Ended |
Dec. 31, 2019 | |
Derivatives and Fair Value [Abstract] | |
Derivatives and Fair Value | 10. DERIVATIVES AND FAIR VALUE The Company uses derivative financial instruments to achieve a more predictable cash flow from crude oil production by reducing the exposure to price fluctuations. See Note 2 for further information. Commodity swaps - In June 2018, the Company entered into commodity swaps at a Dated Brent weighted average of $ 74.00 per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately 400,000 barrels. On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average of $ 66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. If a liability position exceeds $ 10.0 million, the Company would be required to provide a bank letter of credit or deposit cash into an escrow account for the amount by which the liability exceeds $ 10.0 million. These swaps settle on a monthly basis. At December 31, 2019, the unexpired commodity swaps were for an underlying quantity of 274,870 barrels and had a fair value asset position of $ 0.6 million reflected in “Prepayments and other” line of the consolidated balance sheet. Swaps Settlement Period Type of Contract Index Barrels Weighted Average Fixed Price January 2020 to June 2020 Swaps Dated Brent 274,870 66.70 274,870 Put options - During 2016, the Company executed crude oil put contracts as market conditions allowed in order to economically hedge anticipated 2016 and 2017 cash flows from crude oil producing activities. At December 31, 2017, the crude oil put contracts expired. While these commodity swaps and crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes. The crude oil swaps 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 swaps’ fair value includes the impact of the counterparty’s non-performance risk. The crude oil put contracts were measured at fair value using the Black’s option pricing model. Level 2 observable inputs used in the valuation model included 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 put contract fair value included 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 consolidated statements of operations: Years Ended December 31, Derivative Item Statement of Operations Line 2019 2018 2017 (in thousands) Crude oil swaps and put options Realized gain - contract settlements $ 2,439 $ 744 $ 195 Unrealized gain (loss) ( 2,885 ) 3,520 ( 1,227 ) Derivative instruments gain (loss), net $ ( 446 ) $ 4,264 $ ( 1,032 ) |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | 11. ASSET RETIREMENT OBLIGATIONS The following table summarizes the changes in the Company’s asset retirement obligations: Year Ended December 31, (in thousands) 2019 2018 2017 Beginning balance $ 14,816 $ 20,163 $ 18,612 Accretion 812 1,180 951 Additions 595 — — Acquisitions and dispositions — — ( 103 ) Revisions ( 379 ) ( 6,527 ) 703 Ending balance $ 15,844 $ 14,816 $ 20,163 Accretion is recorded in the line item “Depreciation, depletion and amortization” on the consolidated statements of operations. The Company is required under the Etame PSC for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018. In 2018, the Company recorded a downward revision of $ 6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9. The most recently completed abandonment study was in November 2018. In 2019, the Company recorded $ 0.6 million in additions associated with the Etame 9H and Etame 11H development wells . In December 2019, the Company recorded $ 0.4 million downward revision associated with the Mutamba Iroru block onshore Gabon. As discussed further in Note 2, on February 28, 2019, t he Gabonese branch of the 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 for CEMAC for conversion to local currency with a credit back to the Gabonese branch in local currency. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | 12. COMMITMENTS AND CONTINGENCIES FPSO charter In connection with the charter of the FPSO (the “FPSO charter”), the Company, as operator of the Etame Marin block, guaranteed all of the lease payments under the FPSO charter through its contract term, which expires in September 2022. At the Company’s election, the FPSO charter may be terminated as early as September 2020. The Company obtained guarantees from each of the joint owners for their respective shares of the payments. Although the Company believes the need for performance under the charter guarantee is remote, the Company recorded a liability of $ 0.4 million and $ 0.3 million as of December 31, 2019 and 2018, respectively, representing the guarantee’s estimated fair value. Estimated future minimum obligations through the end of the FPSO charter, which reflects the right of early termination in September 2021 are as follows: Balance at December 31, 2019 (in thousands) Full Charter Payment VAALCO, Net Year 2020 $ 32,233 10,010 2021 24,042 7,467 2022 — — 2023 — — 2024 — — Total $ 56,275 $ 17,477 The FPSO charter payment includes a $ 0.93 per barrel charter fee for production up to 20,000 barrels of crude oil per day and a $ 2.50 per barrel charter fee for those barrels produced in excess of 20,000 barrels of crude oil per day. VAALCO’s net share of payments was $ 12.1 million, $ 10.8 million and $ 12.8 million for the years ended December 31, 2019, 2018 and 2017, respectively. Drilling and other commitments In connection with the PSC Extension, the Etame Marin block joint owners are required to drill two wells and two appraisal wellbores by September 16, 2020. As a result of drilling the Etame 9P appraisal wellbore in 2019 and the South East Etame 4P appraisal wellbore in 2020 and drilling the Etame 9H and the Etame 11H development wells in 2019, this drilling commitment has been fulfilled. In addition to the drilling commitment, the Etame Marin block joint owners are required to pay $ 5.0 million ($ 1.7 million, net to VAALCO) in cash to the government of Gabon following the end of the drilling activities for the two wells. As the payment is not contingent on the success of these wells and at least $ 5.0 million would be paid if no wells are drilled, the Company has accrued a liability for the net $ 1.7 million share as of December 31, 2019, which was paid in February 2020. The joint owners are also obligated to perform two technical studies by September 16, 2020 estimated to cost $ 1.3 million ($ 0.4 million, net to VAALCO). These studies are currently being performed. The costs related to these studies will be recognized in future periods when the studies are performed. See Note 13 for discussion related to equipment lease commitments. Drilling Rig In 2019, the Company contracted a drilling rig to be used to drill two wells, including two appraisal wellbores, for the Etame Marin joint operations. The agreement includes options to drill four additional wells at the Etame Marin block, and it elected to exercise these options to drill a third development well and perform three workovers. The drilling rig contract stipulates a day rate of approximately $ 75,000 . The Company expects the term associated with the drilling rig commitment to be less than one year . As of March 9, 2020, the only remaining commitment under the contract was related to two workovers which the Company expects will be completed in the second quarter of 2020. Gabon domestic market obligation and other investment obligations Under the terms of the Etame PSC the Consortium is required to provide to the local government refinery a volume of crude oil at a 15 % discount to market price (the “Gabon DMO”). The volume required to be furnished is the amount of the Etame Marin block production divided by total Gabon production times the volume of crude oil refined by the refinery per year. In 2019, the Company paid $ 1.2 million for the share of the 2018 obligation. In 2018, the Company paid $ 1.1 million for the share of the 2017 obligation. In 2017, the Company paid $ 1.2 million for the share of the 2016 obligation. The Company accrues an amount for the Gabon DMO based on management’s best estimate of the volume of crude oil required because the refinery does not publish throughput figures. The amount accrued at December 31, 2019, for the share of the 2019 obligation was $ 1.1 million. The amount accrued at December 31, 2018, for the share of the 2018 obligation was $ 1.2 million. These costs are cost recoverable under the terms of the Etame PSC. Also, the Consortium is required to pay an additional 1 % of revenues for provisions for diversified investments (“PID”) and for investments in hydrocarbons (“PIH”). The amount accrued at December 31, 2019, for the share of the 2019 obligation was $ 2.2 million. The amount accrued at December 31, 2018, for the share of the 2018 obligation was $ 1.9 million. 75 % of PID and PIH costs are cost recoverable under the terms of the Etame PSC. Abandonment funding Under the terms of the Etame 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 ($ 19.2 million, net to VAALCO) on an undiscounted basis. Through December 31, 2019, $ 36.7 million ($ 11.4 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 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. Regulatory and Joint Interest Audits The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the joint operating agreements. In 2016, the government of Gabon conducted an audit of the 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 response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the currently 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 financial condition, results of operations or liquidity. In 2017, the government of Gabon conducted a tax audit of the Gabon subsidiary covering the years 2013 through 2016, and in December 2017, the Company received a report on their findings. In April 2018, the Company reached a final settlement of the audit resulting in a payment for taxes of $ 0.2 million and penalties of $ 0.2 million, net to VAALCO. At December 31, 2018, the Company had accrued $ 1.3 million, net to VAALCO, in the “Accrued liabilities and other” line item of the consolidated balance sheet for potential fees, which may result from a customs audit. This matter was fully resolved in January 2019 for $ 1.3 million, net to VAALCO. In July 2019, the Company reached an agreement in principle to resolve a legacy issue related to findings from Etame joint venture owners’ audits for the periods from 2007 through 2016 for $ 4.4 million net to VAALCO. The agreement in principle also provides for procedures to minimize the chances of future audit claims. Accordingly, the Company recorded an expense in the consolidated statements of operations in the line item “Other operating income (expense), net”. The final settlement agreements were executed by all the joint venture owners effective September 9, 2019. In October 2019, the Company paid $ 1.1 million of the $ 4.4 million. The balance of the amount due was paid in February 2020. Employment agreements The Company’s Chief Executive Officer has an employment agreement, which provides for payments of annual salary, incentive compensation and certain other benefits if their employment is terminated without cause. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | 13. LEASES Under the new leasing standard that became effective January 1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments. Practical Expedients – The new standard provides a package of three practical expedients to simplify adoption. At the transition date, the entity may elect not to reassess: (1) whether any expired or existing contracts as of the adoption date are or contain leases under the new definition of a lease, (2) lease classification for expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. These three expedients must be elected or not elected as a package. An entity that elects to apply all three of the practical expedients will, in effect, continue to classify leases that commence before the adoption date in accordance with current GAAP, unless the lease classification is reassessed after the adoption date. A lessee that elects to apply all of the practical expedients beginning on the adoption date will follow subsequent measurement guidance in ASC 842. The Company has 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 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 has entered into several agreements for the lease of office, warehouse and storage yard space, the FPSO, a hydraulic workover rig (“HWU”), and a helicopter. The duration for these agreements range from 21 to 45 months. The FPSO, HWU, helicopter, and office space 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, HWU, helicopter, and warehouse and storage yard space used in the joint operations includes the gross amount of the lease components. The ROU asset and lease liability for the HWU was removed from the Company’s consolidated balance sheet when the contract for the HWU was cancelled in December 2019. The FPSO lease includes an option to extend the term through September 2022. T he Company considered this option reasonably certain of exercise and has included it in the calculation of ROU assets and lease liabilities. 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 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. The FPSO agreement also contains options to purchase the assets during or at the end of the lease term. T he Company does not consider these options reasonably certain of exercise and has excluded the purchase price from the calculation of ROU assets and lease liabilities. The FPSO and helicopter 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. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities. 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 year ended December 31, 2019, the components of the lease costs and the supplemental information were as follows: Years Ended December 31, 2019 Lease cost: (in thousands) Operating lease cost $ 16,428 Short-term lease cost 3,470 Variable lease cost 5,819 Total lease expense 25,717 Lease costs capitalized 3,653 Total lease costs $ 29,370 Other information: Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows to operating leases $ 19,229 Weighted-average remaining lease term 2.7 years Weighted-average discount rate 6.18 % The table below describes the presentation of the total lease cost on the Company’s 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. Years Ended December 31, 2019 (in thousands) Production expense $ 7,859 General and administrative expense 196 Lease costs billed to the joint venture owners 20,181 Total lease expense 28,236 Lease costs capitalized 1,134 Total lease costs $ 29,370 The following table describes the future maturities of the Company’s operating lease liabilities at December 31, 2019: Lease Obligation Year (in thousands) 2020 $ 13,655 2021 13,310 2022 9,130 2023 — 2024 — 36,095 Less: imputed interest 2,734 Total lease liabilities $ 33,361 Under the joint operating agreements, other joint owners are obligated to fund $ 24.9 million of the $ 36.1 million in future lease liabilities. With respect to the periods prior to adoption of the new leasing standard, the Company incurred rent expense of $ 17.0 million and $ 19.1 million, respectively, associated with the FPSO and other leased equipment for the years ended December 31, 2018 and 2017. |
Accrued Liabilities and Other
Accrued Liabilities and Other | 12 Months Ended |
Dec. 31, 2019 | |
Accrued Liabilities and Other [Abstract] | |
Accrued Liabilities and Other | 14. ACCRUED LIABILITIES AND OTHER Accrued liabilities and other balances were comprised of the following: December 31, 2019 2018 (in thousands) Accrued accounts payable invoices $ 4,650 $ 4,669 Joint venture audit settlement 3,322 — Gabon DMO, PID and PIH obligations 3,314 3,145 Capital expenditures 11,792 2,038 Stock appreciation rights 2,638 1,007 Accrued wages and other compensation 1,731 1,802 Other 2,326 1,477 Total accrued liabilities and other $ 29,773 $ 14,138 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt [Abstract] | |
Debt | 15. DEBT On May 22, 2018, the Company terminated an amended term loan agreement the Company had with the International Finance Corporation (the “IFC”) (the “Amended Term Loan Agreement”) by prepaying the outstanding principal and accrued interest. The Company did not incur any termination or prepayment penalties as a result of the termination of the Amended Term Loan Agreement. The Company entered into the Amended Term Loan Agreement o n June 29, 2016 through the execution of a Supplemental Agreement with the IFC, which, among other things, amended and restated the existing loan agreement to convert the $ 20.0 million revolving portion of the credit facility, to a term loan with $ 15.0 million outstanding at that date. The Amended Term Loan Agreement was secured by the assets of the Gabon subsidiary, VAALCO Gabon S.A., and was guaranteed by VAALCO as the parent company. The Amended Term Loan Agreement provided for quarterly principal and interest payments on the amounts outstanding, with interest accruing at a rate of LIBOR plus 5.75 %. The Amended Term Loan Agreement also provided for an additional $ 5.0 million, which could be requested in a single draw, subject to the IFC’s approval, through March 15, 2017. On March 14, 2017, the Company borrowed $ 4.2 million under this provision of the Amended Term Loan Agreement. The additional borrowings were to be repaid in five quarterly principal installments commencing June 30, 2017, together with interest, which will accrue at LIBOR plus 5.75 %. Interest Under the terms of the Amended Term Loan Agreement with the IFC, from 2016, through March 14, 2017, commitment fees were equal to 2.3 % of the undrawn term loan amount of $ 5.0 million. There were no further commitment fees owing after March 14, 2017. The table below shows the components of the “Interest expense” line item of the consolidated statements of operations and the average effective interest rate, excluding commitment fees, on the borrowings: Years Ended December 31, 2019 2018 2017 (in thousands) Interest expense related to debt, including commitment fees $ — $ ( 257 ) $ ( 997 ) Deferred finance cost amortization — ( 191 ) ( 369 ) Interest income 733 270 7 Other interest expense not related to debt — 33 ( 55 ) Interest income (expense), net $ 733 $ ( 145 ) $ ( 1,414 ) Average effective interest rate, excluding commitment fees N/A 7.09 % 6.72 % |
Shareholders' Equity
Shareholders' Equity | 12 Months Ended |
Dec. 31, 2019 | |
Shareholders' Equity [Abstract] | |
Shareholders' Equity | 16. 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 December 31, 2019 or 2018. 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 intends to 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 “Exchange Act”.  The Board of Directors also authorized the Company to enter into written trading plans under Rule 10b5-1 of the Exchange Act. Adopting a trading plan that satisfies the conditions of Rule 10b5-1 allows a company to repurchase its shares at times when it might otherwise be prevented from doing so due to self-imposed trading blackout periods or pursuant to insider trading laws. Under any Rule 10b5-1 trading plan, the Company’s third-party broker, subject to Securities and Exchange Commission regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the plan. The Company may from time to time enter into Rule 10b5-1 trading plans to facilitate the repurchase of its common stock pursuant to its share repurchase program. From commencement of the plan in June 2019 through December 31, 2019, the Company purchased 2,067,188 shares of common stock at an average price of $ 1.81 per share for an aggregate purchase price of $ 3.7 million under the plan. From January 1, 2020 through the settlement date of March 5, 2020, the Company has purchased 44,368 shares of its common stock at an average price of $ 1.99 per share for an aggregate purchase price of $ 0.1 million. For the majority of restricted stock awards granted by the Company, the number of shares issued on the date the restricted stock awards vest is net of shares withheld to meet applicable tax withholding requirements. 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 the Financial Statements as they reduce the number of shares that would have been issued upon vesting. See Note 17 for further discussion. |
Stock-Based Compensation and Ot
Stock-Based Compensation and Other Benefit Plans | 12 Months Ended |
Dec. 31, 2019 | |
Stock-Based Compensation and Other Benefit Plans [Abstract] | |
Stock-Based Compensation and Other Benefit Plans | 17. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS The stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Board of Directors to issue various types of incentive compensation. Currently, the Company has issued stock options, restricted shares and SARs from the 2014 Long-Term Incentive Plan (“2014 Plan”). At December 31, 2019, 68,241 shares were authorized for future grants under this plan. For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a one -for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares. The Company records non-cash compensation expense related to stock-based compensation as general and administrative expense. For the years ended December 31, 2019, 2018 and 2017, non-cash compensation expense was $3.5 million, $2.4 million and $1.1 million, respectively, related to the issuance of stock options, restricted stock and SARs. The Company computes a deferred tax benefit for restricted shares, SARs and stock options expected to generate future tax deductions by applying the federal statutory tax rate. For restricted shares, the Company's actual tax deduction is based on the value of the shares at the time of vesting. The Company receives a tax deduction for certain stock option exercises during the period the stock option awards are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. Years Ended December 31, 2019 2018 2017 (in thousands) Stock-based compensation - equity awards $ 985 $ 820 $ 977 Stock-based compensation - liability awards 2,521 1,568 121 Total stock-based compensation $ 3,506 $ 2,388 $ 1,098 Stock options 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 Board of Directors, which in the past has been a five year life, with the options vesting over a service period of up to five years . In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. There were $ 0.3 million, $ 0.5 million and $ 39 thousand in cash proceeds received from the exercise of stock options in 2019, 2018 and 2017, respectively. On February 28, 2019, the Company granted stock options for 622,140 shares to employees; these options vest over a three-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant with an exercise price of $ 2.33 per share. On April 1, 2019, the Company granted stock options for 44,163 shares to an employee with an exercise price of $ 2.29 per share. On June 6, 2019, the Company granted stock options for 257,228 shares to directors with an exercise price of $ 1.43 per share; these options vested immediately. During 2018, options for 494,941 shares were granted to employees; these options vest over a three-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant and have an exercise price of $ 0.86 per share. Options for 175,644 shares also were granted in 2018 to the non-employee directors, which were fully vested upon their grant and have an exercise price of $ 1.60 per share. During 2017, options for 1,162,930 shares were granted to employees; these options vest over a three-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant. Options for 465,950 shares also were granted in 2017 to the non-employee directors, which were fully vested upon their grant. 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 vesting period of the option. During 2019, 2018 and 2017, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants. Because the Company has not paid cash dividends and do not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes model. Years Ended December 31, 2019 2018 2017 Weighted average exercise price - ($/share) $ 2.08 $ 1.05 $ 0.99 Expected life in years 3.2 3.5 3.2 Average expected volatility 73 % 71 % 73 % Risk-free interest rate 2.33 % 2.51 % 1.51 % Weighted average grant date fair value - ($/share) $ 1.06 $ 0.68 $ 0.49 Stock option activity for the year ended December 31, 2019 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, 2019 2,601 $ 1.54 Granted 923 2.08 Exercised ( 260 ) 0.99 Unvested shares forfeited ( 306 ) 1.50 Vested shares expired ( 124 ) 6.70 Outstanding at December 31, 2019 2,834 1.55 2.77 $ 2,301 Exercisable at December 31, 2019 1,858 1.46 2.34 $ 1,736 The intrinsic value of a stock option is the amount that the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of stock options exercised in 2019, 2018 and 2017 was $ 0.3 million, $ 0.6 million and $ 0.0 million, respectively. As of December 31, 2019, unrecognized compensation cost related to outstanding stock options was $ 0.3 million, which is expected to be recognized over a weighted average period of 1.5 years. Restricted shares Restricted stock granted to employees will vest over a period determined by the Compensation Committee, which is generally a three - year period, vesting in three equal parts on the first three anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted. The following is a summary of activity in unvested restricted stock in 2019. Restricted Stock Weighted Average Grant Price (in thousands) Non-vested shares outstanding at January 1, 2019 507 $ 0.91 Awards granted 309 2.00 Awards vested ( 307 ) 1.12 Awards forfeited ( 166 ) 1.29 Non-vested shares outstanding at December 31, 2019 343 1.52 The total vest-date fair value of restricted stock awards, which vested during 2019, 2018 and 2017 was $ 0.6 million, $ 0.4 million and $ 0.3 million, respectively. The weighted average grant date fair value per share of restricted stock awards was $ 2.00 , $ 1.71 and $ 0.98 for the years ended December 31, 2019, 2018 and 2017, respectively. On February 28, 2019, the Company issued 174,464 shares of service based restricted stock to employees with a grant date fair value of $ 2.33 per share. On April 1, 2019, the Company issued 22,926 shares of service based restricted stock to employees with a grant date fair value of $ 2.29 per share. On June 6, 2019, the Company issued 111,888 shares of service based restricted stock to directors with a grant date fair value of $ 1.43 per share, which vested immediately. On February 28, 2018, the Company issued 323,474 shares of service based restricted stock with a grant date fair value of $ 0.86 per share. The vesting of the shares granted to employees is dependent upon the employee’s continued service with the Company. The shares will vest in three equal parts over three years. As of December 31, 2019, unrecognized compensation cost related to restricted stock totaled $ 0.2 million and is expected to be recognized over a weighted average period of 1.5 years. SARs SARs are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights 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 price per share specified in a SAR award on the date of grant, (which may not be less than the fair market value of the common stock on the date of grant), and the fair market value per share 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 Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Board of Directors. On February 28, 2019, 951,699 SARs were granted that vest over a three-year period with a life of 5 years and have a $ 2.33 SAR price per share specified in a SAR award on the date of grant. On May 10, 2019, 196,892 SARs were granted which vest over a three-year period with a life of 5 years and have a $ 1.72 SAR price per share specified in a SAR award on the date of grant. During 2018, 2,373,411 SARs were granted that vest over a three-year period with a life of 5 years and have a $ 0.86 SAR price per share specified in a SAR award on the date of grant. D uring 2017, 1,049,528 SARs were granted, all having an exercise price of $ 1.20 per share. One-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of the Company’s common stock exceeds $ 1.30 ; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds $ 1.50 ; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds $ 1.75 . SARs granted in 2017 vest over a three year period with a life of 5 years . Total compensation expense related to the SARs awards during the year ended December 31, 2019 was $ 2.5 million. SAR activity for the year ended December 31, 2019 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, 2019 3,369 $ 0.96 Granted 1,148 2.23 Exercised ( 558 ) 1.04 Unvested shares forfeited ( 541 ) 1.41 Vested shares expired — — Outstanding at December 31, 2019 3,418 1.30 3.21 $ 3,240 Exercisable at December 31, 2019 952 0.99 2.56 $ 1,173 Other benefit plans The Company sponsors a 401(k) plan, with a company match feature, for the employees. Costs incurred in the years ended December 31, 2019, 2018 and 2017 for the Company’s matching contribution and for administering the plan were approximately $ 0.4 million , $ 0.3 million and $ 0.2 million, respectively. |
Selected Quarterly Financial In
Selected Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2019 | |
Selected Quarterly Financial Information [Abstract] | |
Selected Quarterly Financial Information | SELEC TE D QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The unaudited quarterly results for years ended December 31, 2019 and 2018 were prepared in accordance with GAAP, and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature. Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year. Three Months Ended March 31, June 30, September 30, December 31, (in thousands of dollars except per share information) 2019: Total revenues $ 19,765 $ 25,230 $ 17,603 $ 21,923 Total operating costs and expenses 14,182 14,461 16,137 14,127 Operating income 5,546 6,370 1,501 7,776 Income (loss) from continuing operations 830 ( 871 ) ( 3,858 ) 1,051 Income (loss) from discontinued operations 5,671 ( 162 ) ( 61 ) ( 37 ) Net income (loss) 6,501 ( 1,033 ) ( 3,919 ) 1,014 Basic net income (loss) per share $ 0.10 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Diluted net income (loss) per share $ 0.10 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Basic income (loss) from continuing operations per share $ 0.01 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Diluted income (loss) from continuing operations per share $ 0.01 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Deferred income tax expense (benefit) for the three months ended September 30, 2019 included a $ 4.8 million charge to increase the valuation allowances on US deferred tax assets and for the three months ended December 31, 2019 included $ 1.7 million benefit as a result of a decrease in valuation allowances on deferred tax assets. Three Months Ended March 31, June 30, September 30, December 31, (in thousands of dollars except per share information) 2018: Total revenues $ 27,645 $ 24,426 $ 25,266 $ 27,606 Total operating costs and expenses 14,631 19,017 7,940 12,433 Operating income 13,038 5,723 17,320 15,206 Income from continuing operations 8,711 887 78,626 10,504 Loss from discontinued operations ( 52 ) ( 343 ) ( 21 ) ( 80 ) Net income 8,659 544 78,605 10,424 Basic net income per share $ 0.15 $ 0.02 $ 1.31 $ 0.17 Diluted net income per share $ 0.15 $ 0.02 $ 1.28 $ 0.17 Basic income from continuing operations per share $ 0.15 $ 0.02 $ 1.31 $ 0.17 Diluted income from continuing operations per share $ 0.15 $ 0.02 $ 1.28 $ 0.17 As discussed further in Note 8, deferred income tax expense (benefit) for the three months ended September 30 and December 31, 2018 included $( 66.6 ) million and $ 9.0 million, respectively, related to the recognition of deferred tax assets as well as adjustments to valuation allowances. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Principles of consolidation | Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation. |
Reclassifications | Reclassifications – Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the presentation of stock based compensation and derivatives on the Company’s consolidated statements of cash flows. These reclassifications had no material impact on the Company’s financial position or results of operations. |
Use of estimates | Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the United States (“U.S.”) (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. Estimates of crude oil and natural gas reserves used to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available. |
Cash and cash equivalents | Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. |
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 December 31, 2019 and 2018 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at December 31, 2019 and 2018 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 12. 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 consolidated balance sheets to the amounts shown in the consolidated statement of cash flows. December 31, 2019 2018 (in thousands) Cash and cash equivalents $ 45,917 $ 33,360 Restricted cash - current 911 804 Restricted cash - non-current 925 920 Abandonment funding 11,371 11,571 Total cash, cash equivalents and restricted cash $ 59,124 $ 46,655 The Company conducts regular abandonment studies 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” on the 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 11 for further discussion. On February 28, 2019, the Gabonese branch of the 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 for African Economic and Monetary Community (“ 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 Etame PSC provides these payments must be denominated in U.S. dollars and the CEMAC regulations provide for establishment of a U.S. dollar account with the Central Bank. Although we have requested establishment of such account, the Central Bank has not complied with our requests. As a result, we were not able to make the annual abandonment funding payment in 2019. Amendment No. 5 to the Etame PSC also provides that in the event that the Gabonese bank fails for any reasons to reimburse all of the principal and interest due, the Contractor shall no longer be held liable for the obligation to remediate the sites. |
Accounts with joint owners | Accounts with joint owners – Accounts with joint owners represent the excess of charges billed over cash calls paid by the joint owners for exploration, development and production expenditures made by the Company as an operator. |
Bad debts | Bad debts – Quarterly, the Company evaluates its accounts receivable balances to confirm collectability. 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 consolidated statements of operations. The majority of the accounts receivable balances are with the Company’s joint venture owners, purchasers of the production and 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 costs in Gabon (including the VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). As of December 31, 2019, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF 5.4 billion (XAF 1.8 billion, net to VAALCO). The VAT receivable balance was reduced by XAF 14.1 billion (XAF 4.7 billion, net to VAALCO or $ 4.2 million) associated with a signing bonus as part of the Sixth Amendment to the Etame PSC executed on September 17, 2018 (“PSC Extension”). As of December 31, 2019, the exchange rate was XAF 585.7 = $1.00. In 2019, 2018 and 2017, the Company recorded recoveries (allowances) of $ 0.3 million, $ 0.1 million and $( 0.4 ) million, respectively, related to VAT, which the government of Gabon has not reimbursed. 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 consolidated balance sheets. Because both the VAT receivable and the related allowance 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 profit/loss. Such foreign currency gains/(losses) are reported separately in the “Other, net” line item of the consolidated statements of operations. The following table provides an analysis of the change in the allowance: Years Ended December 31, 2019 2018 2017 (in thousands) Allowance for bad debt Balance at beginning of year $ ( 2,535 ) $ ( 7,033 ) $ ( 5,211 ) Bad debt recovery (charge) 341 77 ( 452 ) Reclassification to leasehold costs related to signing bonus — 4,197 — Reclassification of Sojitz acquisition — — ( 694 ) Adjustment associated with settlement of customs audit 623 — — Foreign currency gain 63 224 ( 676 ) Balance at end of period $ ( 1,508 ) $ ( 2,535 ) $ ( 7,033 ) |
Crude oil inventory | Years Ended December 31, 2019 2018 2017 (in thousands) Allowance for bad debt Balance at beginning of year $ ( 2,535 ) $ ( 7,033 ) $ ( 5,211 ) Bad debt recovery (charge) 341 77 ( 452 ) Reclassification to leasehold costs related to signing bonus — 4,197 — Reclassification of Sojitz acquisition — — ( 694 ) Adjustment associated with settlement of customs audit 623 — — Foreign currency gain 63 224 ( 676 ) Balance at end of period $ ( 1,508 ) $ ( 2,535 ) $ ( 7,033 ) Crude oil inventory – Crude oil inventories are carried at the lower of cost or market and represent the share of crude oil produced and stored on the FPSO, but unsold at the end of the period. |
Materials and supplies | Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the consolidated balance sheet, are primarily used for production related activities. These assets are valued at the lower of cost, determined by the weighted-average method, or market. |
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. |
Capitalization | Capitalizati on – 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 (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. |
Depreciation, depletion and amortization | Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a field-by-field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field-by-field 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. |
Impairment | Impairment – The Company reviews the crude oil and natural gas producing properties for impairment on a field-by-field 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 a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. 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. The Company recorded no material adjustments for inventory obsolescence for the years 2019 or 2017. The Company identified equipment inventory in Gabon that required an adjustment of $ 0.4 million to the “Other operating income (expense), net” line item of the consolidated statement of operations for the year ended December 31, 2018. 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. |
Capitalized interest | Capitalized interest – Interest costs and commitment fees from external borrowings are capitalized on exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets . The Company capitalized no interest costs during the years ended December 31, 2019, 2018 and 2017. |
Lease commitments | Lease commitments – The Company lessees of office buildings, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and are expensed either as production expenses or general and administrative expenses. See Note 13 for further discussion. |
Asset retirement obligations ("ARO") | Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil and natural gas properties. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of 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, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note 11 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. During the year ended December 31, 2018, the Company recorded a downward revision of $ 6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9. In the second half of 2019, the Company recorded $ 0.6 million in additions associated with the spudding of the Etame 9H and Etame 11H development wells at the Etame field in conjunction with commencement of its 2019/2020 drilling campaign and $ 0.4 million downward revision associated with the Mutamba Iroru block onshore Gabon. |
Revenue recognition | Revenue recognition – Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame PSC is not a customer contract. The terms of the Etame 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” 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 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 7 for further discussion. |
Major maintenance activities | Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs. |
Stock-based compensation | Stock-based compensation – The Company measured 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. Grant date fair value for options is estimated using the Black-Scholes option pricing model. The model employs various 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 option award . For restricted stock, grant date fair value is determined using the market value of the common stock on the date of grant. The fair value of stock appreciation rights (“SARs”) is based on a Monte Carlo simulation at grant date and at each subsequent reporting date for the 2016 grants. The Monte Carlo simulation to value the SARs uses 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 SARs, (v) the expected dividend yield is based on the anticipated dividend payments, (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 SARs. The Company utilizes the Black-Scholes option pricing model to measure the fair value of the 2019, 2018 and 2017 SARs. The stock-based compensation expense is recognized based on the awards as they vest, using the straight-line attribution method over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. When awards are forfeited before they vest, previously recognized expense related to such forfeitures is reversed in the period in which the forfeiture occurs. See Note 17 for further discussion. |
Foreign currency transactions | Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries . Gains and losses on foreign currency transactions are included in income. Within the consolidated statements of operations line item “Other income (expense)—Other, net,” the Company recognized losses on foreign currency transactions of $ 0.2 million and $ 0.1 million in 2019 and 2018, respectively, while the Company recognized gains on foreign currency transactions of $ 0.5 million 2017. |
Income taxes | Income taxes – The annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual 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 level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the 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. We also record as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil which results due to change in value from the time the allocation is originally produced to the time the allocation is actually lifted. Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-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 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 expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the consolidated financial position and results of operations. See Note 8 for further discussion. |
Derivative instruments and hedging activities | Derivative instruments and hedging activities – The Company uses derivative financial instruments to achieve a more predictable cash flow from crude oil production by reducing the exposure to price fluctuations. All of the crude oil put contracts, which provided for settlement based upon reported the Brent price, had expired as of December 31, 2017. The Company’s derivative instruments at December 31, 2018, consisted of crude oil swaps, which require the Company to pay a counterparty when the price of crude oil exceeds $ 74.00 per barrel, and where the price of crude oil falls below $ 74.00 , the Company received a payment from the counterparty. On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average of $ 66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. See Note 10 for further discussion. The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments (gain) loss, net” and “Cash settlements received on matured derivative contracts, net” lines items located as adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities on the statements of consolidated cash flows. The Company received net cash settlements of $ 2.4 million, $ 0.7 million and $ 0.2 million during the years ended December 31, 2019, 2018 and 2017, respectively, related to matured derivative contracts. |
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 internally developed present value of future cash flows model that underlies the fair-value measurement). |
Fair value of financial instruments | Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for SARs and guarantee. As discussed further in Note 10, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivative asset commodity swaps referenced below are reported on the consolidated balance sheet on line item “ Prepayments and other.” SARs liabilities are measured and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported on the consolidated balance sheet on line item “Accrued liabilities and other” while the long-term portion is located on the line item “Other long term liabilities”. With respect to the other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. As of December 31, 2019 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 636 $ — $ 636 $ — $ 636 $ — $ 636 Liabilities SARs liability Accrued liabilities $ — $ 2,638 $ — $ 2,638 SARs liability Other long-term liabilities — 852 — 852 $ — $ 3,490 $ — $ 3,490 As of December 31, 2018 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 Liabilities SARs liability Accrued liabilities $ — $ 1,007 $ — $ 1,007 SARs liability Other long-term liabilities — 625 — 625 $ — $ 1,632 $ — $ 1,632 |
Other, net | Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above. In addition, “Other, net” for the year ended December 31, 2017 includes $ 2.6 million related to the reversal of accruals for liabilities the Company was no longer obligated to pay. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Reconciliation of Cash, Cash Equivalents, and Restricted Cash | December 31, 2019 2018 (in thousands) Cash and cash equivalents $ 45,917 $ 33,360 Restricted cash - current 911 804 Restricted cash - non-current 925 920 Abandonment funding 11,371 11,571 Total cash, cash equivalents and restricted cash $ 59,124 $ 46,655 |
Rollforward Analysis of the Allowance Against Accounts Receivable Balance | Years Ended December 31, 2019 2018 2017 (in thousands) Allowance for bad debt Balance at beginning of year $ ( 2,535 ) $ ( 7,033 ) $ ( 5,211 ) Bad debt recovery (charge) 341 77 ( 452 ) Reclassification to leasehold costs related to signing bonus — 4,197 — Reclassification of Sojitz acquisition — — ( 694 ) Adjustment associated with settlement of customs audit 623 — — Foreign currency gain 63 224 ( 676 ) Balance at end of period $ ( 1,508 ) $ ( 2,535 ) $ ( 7,033 ) |
Assets and Liabilities Measured on Recurring Basis | As of December 31, 2019 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 636 $ — $ 636 $ — $ 636 $ — $ 636 Liabilities SARs liability Accrued liabilities $ — $ 2,638 $ — $ 2,638 SARs liability Other long-term liabilities — 852 — 852 $ — $ 3,490 $ — $ 3,490 As of December 31, 2018 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset commodity swaps Prepayments and other $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 $ — $ 3,520 Liabilities SARs liability Accrued liabilities $ — $ 1,007 $ — $ 1,007 SARs liability Other long-term liabilities — 625 — 625 $ — $ 1,632 $ — $ 1,632 |
Dispositions (Tables)
Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Dispositions [Abstract] | |
Summarized Results, Assets and Liabilities Attributable to Discontinued Operations | Summarized Results of Discontinued Operations Years Ended December 31, 2019 2018 2017 (in thousands) Operating costs and expenses: Gain on settlement of drilling obligation $ ( 7,193 ) $ — $ — General and administrative expense 344 467 615 Total operating costs, expenses and (recovery) ( 6,849 ) 467 615 Operating income (loss) 6,849 ( 467 ) ( 615 ) Other income (expense): Other, net — ( 29 ) ( 3 ) Total other income (expense) — ( 29 ) ( 3 ) Income (loss) from discontinued operations before income taxes 6,849 ( 496 ) ( 618 ) Income tax expense 1,438 — 3 Income (loss) from discontinued operations $ 5,411 $ ( 496 ) $ ( 621 ) Assets and Liabilities Attributable to Discontinued Operations December 31, 2019 2018 (in thousands) ASSETS Accounts with joint venture owners $ — $ 3,290 Total current assets — 3,290 Total assets $ — $ 3,290 LIABILITIES Current liabilities: Accounts payable $ 8 $ 73 Accrued liabilities and other 342 15,172 Total current liabilities 350 15,245 Total liabilities $ 350 $ 15,245 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment Information [Abstract] | |
Segment Activity | Years Ended December 31, 2019 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 84,521 $ — $ — $ 84,521 Depreciation, depletion and amortization 6,825 — 258 7,083 Gain on revision of asset retirement obligations ( 379 ) — — ( 379 ) Bad debt recovery and other ( 341 ) — — ( 341 ) Other operating income (expense), net ( 4,456 ) — 35 ( 4,421 ) Operating income (loss) 35,049 ( 438 ) ( 13,418 ) 21,193 Derivatives instruments loss, net — — ( 446 ) ( 446 ) Interest income 5 — 728 733 Other, net ( 230 ) ( 3 ) ( 205 ) ( 438 ) Income tax expense 20,311 12 3,567 23,890 Additions to crude oil and natural gas properties and equipment – accrual 22,116 — 57 22,173 Years Ended December 31, 2018 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 104,938 $ — $ 5 $ 104,943 Depreciation, depletion and amortization 5,176 — 420 5,596 Gain on revision of asset retirement obligations ( 3,325 ) — — ( 3,325 ) Bad debt recovery and other ( 77 ) — — ( 77 ) Other operating income, net 365 — — 365 Operating income (loss) 61,930 ( 470 ) ( 10,173 ) 51,287 Derivatives instruments gain, net — — 4,264 4,264 Interest income (expense), net ( 396 ) — 251 ( 145 ) Other, net 92 ( 4 ) ( 20 ) 68 Income tax benefit ( 26,670 ) — ( 16,584 ) ( 43,254 ) Additions to crude oil and natural gas properties and equipment – accrual 38,430 187 17 38,634 Years Ended December 31, 2017 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Revenues-crude oil and natural gas sales $ 76,978 $ — $ 47 $ 77,025 Depreciation, depletion and amortization 6,196 — 261 6,457 Bad debt expense and other 452 — — 452 Other operating expense, net ( 84 ) — — ( 84 ) Operating income (loss) 28,488 ( 122 ) ( 8,415 ) 19,951 Derivatives instruments loss, net — — ( 1,032 ) ( 1,032 ) Interest expense, net ( 1,414 ) — — ( 1,414 ) Other, net 3,142 15 ( 12 ) 3,145 Income tax expense 11,638 — ( 1,260 ) 10,378 Additions to crude oil and natural gas properties and equipment – accrual 1,576 — 126 1,702 |
Long-lived Assets From Continuing Operations | (in thousands) Gabon Equatorial Guinea Corporate and Other Total Long-lived assets from continuing operations: As of December 31, 2019 $ 57,930 $ 10,000 $ 328 $ 68,258 As of December 31, 2018 $ 42,195 $ 10,187 $ 342 52,724 (in thousands) Gabon Equatorial Guinea Corporate and Other Total Total assets from continuing operations: As of December 31, 2019 $ 151,686 $ 10,087 $ 49,764 $ 211,537 As of December 31, 2018 $ 103,401 $ 10,320 $ 49,301 163,022 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Schedule of Diluted Shares | Years Ended December 31, 2019 2018 2017 (in thousands) Net income (loss) (numerator): Income (loss) from continuing operations $ ( 2,848 ) $ 98,728 $ 10,272 (Income) loss from continuing operations attributable to unvested shares 21 ( 1,231 ) ( 62 ) Numerator for basic ( 2,827 ) 97,497 10,210 Loss from continuing operations attributable to unvested shares ( 21 ) — — Numerator for dilutive $ ( 2,848 ) $ 97,497 $ 10,210 Income (loss) from discontinued operations, net of tax $ 5,411 $ ( 496 ) $ ( 621 ) (Income) loss from discontinued operations attributable to unvested shares ( 39 ) 6 4 Numerator for basic 5,372 ( 490 ) ( 617 ) Income from discontinued operations attributable to unvested shares 39 — — Numerator for dilutive $ 5,411 $ ( 490 ) $ ( 617 ) Net income $ 2,563 $ 98,232 $ 9,651 Net income attributable to unvested shares ( 18 ) ( 1,225 ) ( 58 ) Numerator for basic 2,545 97,007 9,593 Net income attributable to unvested shares 18 — — Numerator for dilutive $ 2,563 $ 97,007 $ 9,593 Weighted average shares (denominator): Basic weighted average shares outstanding 59,143 59,248 58,717 Effect of dilutive securities — 749 3 Diluted weighted average shares outstanding 59,143 59,997 58,720 Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive 603 1,316 2,823 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue [Abstract] | |
Revenues From Contracts With Customers | Years Ended December 31, 2019 2018 2017 Revenue from customer contracts: (in thousands) Sales under the COSPA $ 86,554 $ 104,891 $ 74,693 Gabonese government share of Profit Oil — 2,193 11,638 U.S. crude oil and natural gas revenue — 5 47 Other items reported in revenue not associated with customer contracts: Gabonese government share of Profit Oil taken in-kind 7,268 9,385 — Carried interest recoupment 2,950 3,545 2,205 Royalties ( 12,251 ) ( 15,076 ) ( 11,558 ) Total revenue, net $ 84,521 $ 104,943 $ 77,025 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Taxes [Abstract] | |
Provision for Income Taxes | Years Ended December 31, 2019 2018 2017 U.S. Federal: (in thousands) Current $ ( 337 ) $ ( 674 ) $ — Deferred 3,916 ( 15,910 ) ( 1,260 ) Foreign: Current 9,747 14,327 11,638 Deferred 10,564 ( 40,997 ) — Total $ 23,890 $ ( 43,254 ) $ 10,378 |
Summary of Differences between the Financial Statement and Tax Bases of Assets and Liabilities | As of December 31, (in thousands) 2019 2018 Deferred tax assets: Basis difference in fixed assets $ 26,590 $ 38,479 Foreign tax credit carryforward 34,144 43,760 Alternative minimum tax credit carryover 337 674 U.S. federal net operating losses 30,572 20,616 Foreign net operating losses 11,770 19,989 Asset retirement obligations 3,407 3,111 Basis difference in accrued liabilities 676 3,816 Basis difference in receivables 171 387 Other 1,120 180 Total deferred tax assets 108,787 131,012 Valuation allowance ( 84,628 ) ( 90,935 ) Net deferred tax assets $ 24,159 $ 40,077 |
Pretax Income | Year Ended December 31, (in thousands) 2019 2018 2017 U.S. $ ( 13,330 ) $ ( 5,672 ) $ ( 9,453 ) Foreign 34,372 61,146 30,103 $ 21,042 $ 55,474 $ 20,650 |
Statutory Rate Reconciliation | Year Ended December 31, (in thousands) 2019 2018 2017 Tax provision computed at U.S. statutory rate $ 4,386 $ 11,650 $ 7,228 Foreign taxes not offset in U.S. by foreign tax credits 16,015 24,840 6,775 Impact of Tax Reform Act — — 52,449 Recognition of foreign deferred tax assets, net of U.S. impact — ( 45,751 ) — Unrealizable foreign deferred tax assets — 24,176 — Effect of change in foreign statutory rates — — — Permanent differences 180 ( 104 ) 309 Foreign tax credit expirations 9,616 4,311 2,394 Increase/(decrease) in valuation allowance ( 6,307 ) ( 62,270 ) ( 58,777 ) Other — ( 106 ) — Total income tax expense (benefit) $ 23,890 $ ( 43,254 ) $ 10,378 |
Income Tax Years Subject to Examination by Major Tax Jurisdictions | Jurisdiction Years U.S. 2009 -2019 Gabon 2015 -2019 |
Derivatives and Fair Value (Tab
Derivatives and Fair Value (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivatives and Fair Value [Abstract] | |
Summary of Commodity Swaps | Swaps Settlement Period Type of Contract Index Barrels Weighted Average Fixed Price January 2020 to June 2020 Swaps Dated Brent 274,870 66.70 274,870 |
Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations | Years Ended December 31, Derivative Item Statement of Operations Line 2019 2018 2017 (in thousands) Crude oil swaps and put options Realized gain - contract settlements $ 2,439 $ 744 $ 195 Unrealized gain (loss) ( 2,885 ) 3,520 ( 1,227 ) Derivative instruments gain (loss), net $ ( 446 ) $ 4,264 $ ( 1,032 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligations [Abstract] | |
Summary of Changes in Asset Retirement Obligations | Year Ended December 31, (in thousands) 2019 2018 2017 Beginning balance $ 14,816 $ 20,163 $ 18,612 Accretion 812 1,180 951 Additions 595 — — Acquisitions and dispositions — — ( 103 ) Revisions ( 379 ) ( 6,527 ) 703 Ending balance $ 15,844 $ 14,816 $ 20,163 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies [Abstract] | |
Estimated Obligations and Companies Share for the Annual Charter Payment | Balance at December 31, 2019 (in thousands) Full Charter Payment VAALCO, Net Year 2020 $ 32,233 10,010 2021 24,042 7,467 2022 — — 2023 — — 2024 — — Total $ 56,275 $ 17,477 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Components of Lease Costs | Years Ended December 31, 2019 Lease cost: (in thousands) Operating lease cost $ 16,428 Short-term lease cost 3,470 Variable lease cost 5,819 Total lease expense 25,717 Lease costs capitalized 3,653 Total lease costs $ 29,370 Other information: Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows to operating leases $ 19,229 Weighted-average remaining lease term 2.7 years Weighted-average discount rate 6.18 % |
Lease Cost on Consolidated Statement of Operations | Years Ended December 31, 2019 (in thousands) Production expense $ 7,859 General and administrative expense 196 Lease costs billed to the joint venture owners 20,181 Total lease expense 28,236 Lease costs capitalized 1,134 Total lease costs $ 29,370 |
Schedule of Future Maturities of Operating Lease Liabilities | Lease Obligation Year (in thousands) 2020 $ 13,655 2021 13,310 2022 9,130 2023 — 2024 — 36,095 Less: imputed interest 2,734 Total lease liabilities $ 33,361 |
Accrued Liabilities and Other (
Accrued Liabilities and Other (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accrued Liabilities and Other [Abstract] | |
Schedule of Accrued Liabilities ant Other Balances | December 31, 2019 2018 (in thousands) Accrued accounts payable invoices $ 4,650 $ 4,669 Joint venture audit settlement 3,322 — Gabon DMO, PID and PIH obligations 3,314 3,145 Capital expenditures 11,792 2,038 Stock appreciation rights 2,638 1,007 Accrued wages and other compensation 1,731 1,802 Other 2,326 1,477 Total accrued liabilities and other $ 29,773 $ 14,138 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt [Abstract] | |
Schedule of Interest Information | Years Ended December 31, 2019 2018 2017 (in thousands) Interest expense related to debt, including commitment fees $ — $ ( 257 ) $ ( 997 ) Deferred finance cost amortization — ( 191 ) ( 369 ) Interest income 733 270 7 Other interest expense not related to debt — 33 ( 55 ) Interest income (expense), net $ 733 $ ( 145 ) $ ( 1,414 ) Average effective interest rate, excluding commitment fees N/A 7.09 % 6.72 % |
Stock-Based Compensation and _2
Stock-Based Compensation and Other Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Stock-Based Compensation and Other Benefit Plans [Abstract] | |
Summary of Stock-Based Compensation | Years Ended December 31, 2019 2018 2017 (in thousands) Stock-based compensation - equity awards $ 985 $ 820 $ 977 Stock-based compensation - liability awards 2,521 1,568 121 Total stock-based compensation $ 3,506 $ 2,388 $ 1,098 |
Stock Option Valuation Assumptions | Years Ended December 31, 2019 2018 2017 Weighted average exercise price - ($/share) $ 2.08 $ 1.05 $ 0.99 Expected life in years 3.2 3.5 3.2 Average expected volatility 73 % 71 % 73 % Risk-free interest rate 2.33 % 2.51 % 1.51 % Weighted average grant date fair value - ($/share) $ 1.06 $ 0.68 $ 0.49 |
Stock Option Activity | 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, 2019 2,601 $ 1.54 Granted 923 2.08 Exercised ( 260 ) 0.99 Unvested shares forfeited ( 306 ) 1.50 Vested shares expired ( 124 ) 6.70 Outstanding at December 31, 2019 2,834 1.55 2.77 $ 2,301 Exercisable at December 31, 2019 1,858 1.46 2.34 $ 1,736 |
Summary of Non Vested Awards | Restricted Stock Weighted Average Grant Price (in thousands) Non-vested shares outstanding at January 1, 2019 507 $ 0.91 Awards granted 309 2.00 Awards vested ( 307 ) 1.12 Awards forfeited ( 166 ) 1.29 Non-vested shares outstanding at December 31, 2019 343 1.52 |
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, 2019 3,369 $ 0.96 Granted 1,148 2.23 Exercised ( 558 ) 1.04 Unvested shares forfeited ( 541 ) 1.41 Vested shares expired — — Outstanding at December 31, 2019 3,418 1.30 3.21 $ 3,240 Exercisable at December 31, 2019 952 0.99 2.56 $ 1,173 |
Selected Quarterly Financial _2
Selected Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Selected Quarterly Financial Information [Abstract] | |
Summary of Quarterly Financial Information | Three Months Ended March 31, June 30, September 30, December 31, (in thousands of dollars except per share information) 2019: Total revenues $ 19,765 $ 25,230 $ 17,603 $ 21,923 Total operating costs and expenses 14,182 14,461 16,137 14,127 Operating income 5,546 6,370 1,501 7,776 Income (loss) from continuing operations 830 ( 871 ) ( 3,858 ) 1,051 Income (loss) from discontinued operations 5,671 ( 162 ) ( 61 ) ( 37 ) Net income (loss) 6,501 ( 1,033 ) ( 3,919 ) 1,014 Basic net income (loss) per share $ 0.10 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Diluted net income (loss) per share $ 0.10 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Basic income (loss) from continuing operations per share $ 0.01 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Diluted income (loss) from continuing operations per share $ 0.01 $ ( 0.01 ) $ ( 0.07 ) $ 0.02 Deferred income tax expense (benefit) for the three months ended September 30, 2019 included a $ 4.8 million charge to increase the valuation allowances on US deferred tax assets and for the three months ended December 31, 2019 included $ 1.7 million benefit as a result of a decrease in valuation allowances on deferred tax assets. Three Months Ended March 31, June 30, September 30, December 31, (in thousands of dollars except per share information) 2018: Total revenues $ 27,645 $ 24,426 $ 25,266 $ 27,606 Total operating costs and expenses 14,631 19,017 7,940 12,433 Operating income 13,038 5,723 17,320 15,206 Income from continuing operations 8,711 887 78,626 10,504 Loss from discontinued operations ( 52 ) ( 343 ) ( 21 ) ( 80 ) Net income 8,659 544 78,605 10,424 Basic net income per share $ 0.15 $ 0.02 $ 1.31 $ 0.17 Diluted net income per share $ 0.15 $ 0.02 $ 1.28 $ 0.17 Basic income from continuing operations per share $ 0.15 $ 0.02 $ 1.31 $ 0.17 Diluted income from continuing operations per share $ 0.15 $ 0.02 $ 1.28 $ 0.17 As discussed further in Note 8, deferred income tax expense (benefit) for the three months ended September 30 and December 31, 2018 included $( 66.6 ) million and $ 9.0 million, respectively, related to the recognition of deferred tax assets as well as adjustments to valuation allowances. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands, in Billions | May 06, 2019$ / bblbbl | Sep. 26, 2018USD ($) | Sep. 17, 2018USD ($) | Sep. 17, 2018XAF ( ) | Dec. 31, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2019USD ($)bbl | Dec. 31, 2018USD ($)$ / bbl | Dec. 31, 2017USD ($) | Dec. 31, 2019XAF ( ) / $ |
Organization And Accounting Policies [Line Items] | ||||||||||
Reduction in VAT receivable | $ 275 | $ (777) | $ (3,025) | |||||||
Exchange rate | / $ | 585.7 | |||||||||
Bad debt recovery (expense) | 341 | 77 | (452) | |||||||
Inventory adjustment | 0 | 0 | ||||||||
Interest Costs Capitalized | 0 | 0 | 0 | |||||||
Asset retirement obligation, revision of estimate | $ (400) | $ (379) | $ (6,527) | 703 | ||||||
Monthly royalty rate, based on production at the published price | 13.00% | |||||||||
Working interest of carried partner, percentage | 7.50% | |||||||||
Future working interest of carried partner percentage | 10.00% | |||||||||
Derivative cap price | $ / bbl | 74 | |||||||||
Derivative floor price | $ / bbl | 74 | |||||||||
Gain (loss) on foreign currency transactions | $ (200) | $ (100) | 500 | |||||||
Barrels | bbl | 274,870 | |||||||||
Cash received to settle derivatives | $ 2,400 | 700 | 200 | |||||||
Restatement Adjustment [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Accrued liabilities | (2,600) | |||||||||
Office Equipment [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Estimated useful life | 5 years | |||||||||
Leasehold Improvements [Member] | Minimum [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Estimated useful life | 5 years | |||||||||
Leasehold Improvements [Member] | Maximum [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Estimated useful life | 7 years | |||||||||
Gabon [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Receivable balance, gross | | 5.4 | |||||||||
Receivable balance, net, noncurrent | | 1.8 | |||||||||
Reduction in VAT receivable, gross amount | $ 25,000 | 14.1 | ||||||||
Reduction in VAT receivable | $ 8,400 | $ 4,200 | 4.7 | |||||||
Bad debt recovery (expense) | $ 300 | 100 | $ (400) | |||||||
Inventory adjustment | 400 | |||||||||
Asset retirement obligation, revision of estimate | $ 400 | |||||||||
Etame Field [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Asset retirement obligation, revision of estimate | $ 600 | $ (6,500) | ||||||||
Commodity Contract, July 19 Through June 2020 [Member] | ||||||||||
Organization And Accounting Policies [Line Items] | ||||||||||
Derivative, average price per barrel | $ / bbl | 66.70 | |||||||||
Barrels | bbl | 500,000 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies (Reconciliation of Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Summary Of Significant Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 45,917 | $ 33,360 | ||
Restricted cash - current | 911 | 804 | ||
Restricted cash - non-current | 925 | 920 | ||
Abandonment funding | 11,371 | 11,571 | ||
Total cash, cash equivalents and restricted cash | $ 59,124 | $ 46,655 | $ 32,286 | $ 30,643 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies (Rollforward Analysis of the Allowance Against Accounts Receivable Balance) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Summary Of Significant Accounting Policies [Abstract] | |||
Balance at beginning of year | $ (2,535) | $ (7,033) | $ (5,211) |
Bad debt recovery (charge) | 341 | 77 | (452) |
Reclassification of leasehold costs related to signing bonus | 4,197 | ||
Reclassification of Sojitz acquisition | (694) | ||
Adjustment associated with settlement of customs audit | 623 | ||
Foreign currency gain | 63 | 224 | (676) |
Balance at end of period | $ (1,508) | $ (2,535) | $ (7,033) |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies (Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset commodity | $ 636 | $ 3,520 |
Assets | 636 | 3,520 |
SARs liability | 2,638 | 1,007 |
SARs liability | 852 | 625 |
Liabilities | 3,490 | 1,632 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset commodity | 636 | 3,520 |
Assets | 636 | 3,520 |
SARs liability | 2,638 | 1,007 |
SARs liability | 852 | 625 |
Liabilities | $ 3,490 | $ 1,632 |
New Accounting Standards (Narra
New Accounting Standards (Narrative) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 |
Right of use operating lease assets | $ 33,383 | |
Operating lease liabilities | 11,990 | |
Long-term operating lease liabilities | $ 21,371 | |
Accounting Standards Update 2016-02 [Member] | ||
Right of use operating lease assets | $ 38,900 | |
Operating lease liabilities | 10,200 | |
Long-term operating lease liabilities | $ 28,700 |
Dispositions (Narrative) (Detai
Dispositions (Narrative) (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||
Jul. 31, 2019USD ($) | Apr. 30, 2017USD ($) | Nov. 30, 2006 | Dec. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Jun. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2019USD ($)item | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2015item | |
Business Acquisition [Line Items] | |||||||||||||||
Proceeds from sale of crude oil and natural gas properties | $ 250,000 | ||||||||||||||
Liability for the potential payment | $ 4,400,000 | ||||||||||||||
Income (loss) from discontinued operations, net of tax | $ (37,000) | $ (61,000) | $ (162,000) | $ 5,671,000 | $ (80,000) | $ (21,000) | $ (343,000) | $ (52,000) | $ 5,411,000 | $ (496,000) | (621,000) | ||||
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% | ||||||||||||||
Number of wells drilled | item | 1 | ||||||||||||||
Number of drilled wells required by agreement | item | 3 | ||||||||||||||
Stipulated payment for each exploration well, under PSA terms | $ 10,000,000 | ||||||||||||||
Drilling commitment, net | $ 5,000,000 | 5,000,000 | |||||||||||||
Liability for the potential payment | $ 15,000,000 | 15,000,000 | |||||||||||||
East Poplar Dome Field [Member] | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Proceeds from sale of crude oil and natural gas properties | $ 300,000 | ||||||||||||||
Gain from sale of property | 300,000 | ||||||||||||||
Discontinued Operations [Member] | Joint Operating With Republic Of Angola [Member] | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Liability for the potential payment | 4,500,000 | ||||||||||||||
Write off of receivable | 3,300,000 | ||||||||||||||
Income (loss) from discontinued operations, net of tax | $ 5,700,000 | $ 5,411,000 | $ (496,000) | $ (621,000) | |||||||||||
Payment for settlement | $ 4,500,000 |
Dispositions (Summarized Result
Dispositions (Summarized Results of Discontinued Operations) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||
Income (loss) from discontinued operations | $ (37,000) | $ (61,000) | $ (162,000) | $ 5,671,000 | $ (80,000) | $ (21,000) | $ (343,000) | $ (52,000) | $ 5,411,000 | $ (496,000) | $ (621,000) |
Discontinued Operations [Member] | Joint Operating With Republic Of Angola [Member] | |||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||
Gain on settlement of drilling obligation | (7,193,000) | ||||||||||
General and administrative expense | 344,000 | 467,000 | 615,000 | ||||||||
Total operating costs, expenses and (recovery) | (6,849,000) | 467,000 | 615,000 | ||||||||
Operating income (loss) | 6,849,000 | (467,000) | (615,000) | ||||||||
Other, net | (29,000) | (3,000) | |||||||||
Total other income (expense) | (29,000) | (3,000) | |||||||||
Income (loss) from discontinued operations before income taxes | 6,849,000 | (496,000) | (618,000) | ||||||||
Income tax expense | 1,438,000 | 3,000 | |||||||||
Income (loss) from discontinued operations | $ 5,700,000 | $ 5,411,000 | $ (496,000) | $ (621,000) |
Dispositions (Assets and Liabil
Dispositions (Assets and Liabilities Attributable to Discontinued Operations) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Total current assets | $ 3,290 | |
Total current liabilities | $ 350 | 15,245 |
Joint Operating With Republic Of Angola [Member] | Discontinued Operations [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Accounts with joint venture owners | 3,290 | |
Total current assets | 3,290 | |
Total assets | 3,290 | |
Accounts payable | 8 | 73 |
Accrued liabilities and other | 342 | 15,172 |
Total current liabilities | 350 | 15,245 |
Total liabilities | $ 350 | $ 15,245 |
Segment Information (Narrative)
Segment Information (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2019segment | |
Concentration Risk [Line Items] | |
Number of reportable operating segments | 2 |
Sales Revenue, Net [Member] | Glencore [Member] | |
Concentration Risk [Line Items] | |
Concentration risk, percentage | 6.00% |
Sales Revenue, Net [Member] | Mercuria [Member] | |
Concentration Risk [Line Items] | |
Concentration risk, percentage | 94.00% |
Segment Information (Segment Ac
Segment Information (Segment Activity) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |||||||||||
Revenues-crude oil and natural gas sales | $ 21,923 | $ 17,603 | $ 25,230 | $ 19,765 | $ 27,606 | $ 25,266 | $ 24,426 | $ 27,645 | $ 84,521 | $ 104,943 | $ 77,025 |
Depreciation, depletion and amortization | 7,083 | 5,596 | 6,457 | ||||||||
Bad debt (recovery) expense and other | (341) | (77) | 452 | ||||||||
Gain on revision of asset retirement obligations | (379) | (3,325) | |||||||||
Other operating income (expense), net | (4,421) | 365 | (84) | ||||||||
Operating income (loss) | $ 7,776 | $ 1,501 | $ 6,370 | $ 5,546 | $ 15,206 | $ 17,320 | $ 5,723 | $ 13,038 | 21,193 | 51,287 | 19,951 |
Derivative instruments loss, net | (446) | 4,264 | (1,032) | ||||||||
Interest income (expense), net | 733 | (145) | (1,414) | ||||||||
Other, net | (438) | 68 | 3,145 | ||||||||
Income tax expense (benefit) | 23,890 | (43,254) | 10,378 | ||||||||
Additions to crude oil and natural gas properties and equipment - accrual | 22,173 | 38,634 | 1,702 | ||||||||
Gabon Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues-crude oil and natural gas sales | 76,978 | ||||||||||
Depreciation, depletion and amortization | 6,196 | ||||||||||
Bad debt (recovery) expense and other | 452 | ||||||||||
Other operating income (expense), net | (84) | ||||||||||
Operating income (loss) | 28,488 | ||||||||||
Interest income (expense), net | (1,414) | ||||||||||
Other, net | 3,142 | ||||||||||
Income tax expense (benefit) | 11,638 | ||||||||||
Additions to crude oil and natural gas properties and equipment - accrual | 1,576 | ||||||||||
Equatorial Guinea Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating income (loss) | (122) | ||||||||||
Other, net | 15 | ||||||||||
Operating Segments [Member] | Gabon Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues-crude oil and natural gas sales | 84,521 | 104,938 | |||||||||
Depreciation, depletion and amortization | 6,825 | 5,176 | |||||||||
Bad debt (recovery) expense and other | (341) | (77) | |||||||||
Gain on revision of asset retirement obligations | (379) | (3,325) | |||||||||
Other operating income (expense), net | (4,456) | 365 | |||||||||
Operating income (loss) | 35,049 | 61,930 | |||||||||
Interest income (expense), net | 5 | (396) | |||||||||
Other, net | (230) | 92 | |||||||||
Income tax expense (benefit) | 20,311 | (26,670) | |||||||||
Additions to crude oil and natural gas properties and equipment - accrual | 22,116 | 38,430 | |||||||||
Operating Segments [Member] | Equatorial Guinea Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating income (loss) | (438) | (470) | |||||||||
Other, net | (3) | (4) | |||||||||
Income tax expense (benefit) | 12 | ||||||||||
Additions to crude oil and natural gas properties and equipment - accrual | 187 | ||||||||||
Corporate and Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues-crude oil and natural gas sales | 5 | 47 | |||||||||
Depreciation, depletion and amortization | 258 | 420 | 261 | ||||||||
Other operating income (expense), net | 35 | ||||||||||
Operating income (loss) | (13,418) | (10,173) | (8,415) | ||||||||
Derivative instruments loss, net | (446) | 4,264 | (1,032) | ||||||||
Interest income (expense), net | 728 | 251 | |||||||||
Other, net | (205) | (20) | (12) | ||||||||
Income tax expense (benefit) | 3,567 | (16,584) | (1,260) | ||||||||
Additions to crude oil and natural gas properties and equipment - accrual | $ 57 | $ 17 | $ 126 |
Segment Information (Long-lived
Segment Information (Long-lived Assets from Continuing Operations) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Segment Reporting Information [Line Items] | ||
Total assets | $ 211,537 | $ 166,312 |
Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 68,258 | 52,724 |
Total assets | 211,537 | 163,022 |
Operating Segments [Member] | Gabon Segment [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 57,930 | 42,195 |
Total assets | 151,686 | 103,401 |
Operating Segments [Member] | Equatorial Guinea Segment [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 10,000 | 10,187 |
Total assets | 10,087 | 10,320 |
Corporate and Other [Member] | Continuing Operations [Member] | ||
Segment Reporting Information [Line Items] | ||
Long lived assets | 328 | 342 |
Total assets | $ 49,764 | $ 49,301 |
Earnings Per Share (Schedule of
Earnings Per Share (Schedule of Diluted Shares) (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule of Diluted shares | |||||||||||
Income (loss) from continuing operations | $ 1,051 | $ (3,858) | $ (871) | $ 830 | $ 10,504 | $ 78,626 | $ 887 | $ 8,711 | $ (2,848) | $ 98,728 | $ 10,272 |
Income (loss) from continuing operations attributable to unvested shares | 21 | (1,231) | (62) | ||||||||
Numerator for basic | (2,827) | 97,497 | 10,210 | ||||||||
Loss from continuing operations attributable to unvested shares | (21) | ||||||||||
Numerator for dilutive | (2,848) | 97,497 | 10,210 | ||||||||
Income (loss) from discontinued operations, net of tax | (37) | (61) | (162) | 5,671 | (80) | (21) | (343) | (52) | 5,411 | (496) | (621) |
Income (loss) from discontinued operations attributable to unvested shares | (39) | 6 | 4 | ||||||||
Numerator for basic | 5,372 | (490) | (617) | ||||||||
Income from discontinued operations attributable to unvested shares | (39) | ||||||||||
Numerator for dilutive | 5,411 | (490) | (617) | ||||||||
Net income | $ 1,014 | $ (3,919) | $ (1,033) | $ 6,501 | $ 10,424 | $ 78,605 | $ 544 | $ 8,659 | 2,563 | 98,232 | 9,651 |
Net income attributable to unvested shares | (18) | (1,225) | (58) | ||||||||
Numerator for basic | 2,545 | 97,007 | 9,593 | ||||||||
Net income attributable to unvested shares | (18) | ||||||||||
Numerator for dilutive | $ 2,563 | $ 97,007 | $ 9,593 | ||||||||
Basic weighted average shares outstanding | 59,143 | 59,248 | 58,717 | ||||||||
Effect of dilutive securities | 749 | 3 | |||||||||
Diluted weighted average shares outstanding | 59,143 | 59,997 | 58,720 | ||||||||
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive | 603 | 1,316 | 2,823 |
Revenue (Narrative) (Details)
Revenue (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Initial crude oil sales and purchase agreement period | 1 year | |
Interval period, between lifting | 30 days | |
Monthly royalty rate, based on production at the published price | 13.00% | |
Working interest of carried partner, percentage | 7.50% | |
Income taxes paid in-kind with crude oil | $ 7,268 | $ 9,385 |
Future working interest of carried partner percentage | 10.00% | |
Foreign taxes payable attributable to sharing obligation | $ 5,700 | |
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 |
Revenue (Revenues from Contract
Revenue (Revenues from Contracts with Customers) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | |||||||||||
Royalties | $ (12,251) | $ (15,076) | $ (11,558) | ||||||||
Total revenue, net | $ 21,923 | $ 17,603 | $ 25,230 | $ 19,765 | $ 27,606 | $ 25,266 | $ 24,426 | $ 27,645 | 84,521 | 104,943 | 77,025 |
Sales Under COSPA [Member] | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from customer contracts | 86,554 | 104,891 | 74,693 | ||||||||
Gabonese Government Share Of Profit Oil [Member] | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from customer contracts | 2,193 | 11,638 | |||||||||
Revenue not from customer contracts | 7,268 | 9,385 | |||||||||
US Crude Oil And Natural Gas [Member] | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from customer contracts | 5 | 47 | |||||||||
Carried Interest Recoupment [Member] | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Carried interest recoupment | $ 2,950 | $ 3,545 | $ 2,205 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)item | Dec. 31, 2018USD ($) | Dec. 31, 2017 | |
Income Taxes [Line Items] | |||
Deferred tax assets | $ 108,787 | $ 131,012 | |
Valuation allowance | $ 84,628 | $ 90,935 | |
Statutory tax rate | 21.00% | 21.00% | 35.00% |
Expired foreign tax credits | $ 9,600 | ||
Interest or penalties accrued | $ 0 | $ 0 | |
Production license agreement term extended by government | 5 years | ||
Deferred tax assets | $ 24,159 | $ 40,077 | |
Prior Production Sharing Contract, Through September 17, 2018 [Member] | |||
Income Taxes [Line Items] | |||
Entitled percent for consortium after initial royalty percentage | 70.00% | ||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | |||
Income Taxes [Line Items] | |||
Entitled percent for consortium after initial royalty percentage | 80.00% | ||
Production Sharing Contract, After September 16, 2028 [Member] | |||
Income Taxes [Line Items] | |||
Entitled percent for consortium after initial royalty percentage | 70.00% | ||
United Kingdom Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Deferred tax assets | $ 8,700 | ||
Gabon Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Deferred tax assets | $ 15,900 | ||
Minimum [Member] | |||
Income Taxes [Line Items] | |||
Allocation of remaining profit production, government payments, percentage | 50.00% | ||
Number of contract extension periods | item | 2 | ||
Minimum [Member] | Domestic Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Foreign tax credit carryforward, expiration dates | Dec. 31, 2035 | ||
Minimum [Member] | Foreign Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Foreign tax credit carryforward, expiration dates | Dec. 31, 2020 | ||
Maximum [Member] | |||
Income Taxes [Line Items] | |||
Allocation of remaining profit production, government payments, percentage | 60.00% | ||
Maximum [Member] | Domestic Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Foreign tax credit carryforward, expiration dates | Dec. 31, 2037 | ||
Maximum [Member] | Foreign Tax Authority [Member] | |||
Income Taxes [Line Items] | |||
Foreign tax credit carryforward, expiration dates | Dec. 31, 2025 |
Income Taxes (Provision for Inc
Income Taxes (Provision for Income Taxes) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes [Abstract] | |||
U.S. Federal: Current | $ (337) | $ (674) | |
U. S. Federal: Deferred | 3,916 | (15,910) | $ (1,260) |
Foreign: Current | 9,747 | 14,327 | 11,638 |
Foreign: Deferred | 10,564 | (40,997) | |
Total income tax expense (benefit) | $ 23,890 | $ (43,254) | $ 10,378 |
Income Taxes (Summary Of Differ
Income Taxes (Summary Of Differences Between The Financial Statement And Tax Bases Of Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred Tax Assets: | ||
Deferred tax assets, basis difference in fixed assets | $ 26,590 | $ 38,479 |
Foreign tax credit carryforward | 34,144 | 43,760 |
Alternative minimum tax credit carryover | 337 | 674 |
U.S. federal net operating losses | 30,572 | 20,616 |
Foreign net operating losses | 11,770 | 19,989 |
Asset retirement obligations | 3,407 | 3,111 |
Basis difference in accrued liabilities | 676 | 3,816 |
Basis difference in receivables | 171 | 387 |
Other | 1,120 | 180 |
Total deferred tax assets | 108,787 | 131,012 |
Valuation allowance | (84,628) | (90,935) |
Net deferred tax assets | $ 24,159 | $ 40,077 |
Income Taxes (Pretax Income) (D
Income Taxes (Pretax Income) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pretax income | |||
United States | $ (13,330) | $ (5,672) | $ (9,453) |
Foreign | 34,372 | 61,146 | 30,103 |
Income from continuing operations before income taxes | $ 21,042 | $ 55,474 | $ 20,650 |
Income Taxes (Statutory Rate Re
Income Taxes (Statutory Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statutory rate reconciliation | |||
Tax provision computed at U.S. statutory rate | $ 4,386 | $ 11,650 | $ 7,228 |
Foreign taxes not offset in U.S. by foreign tax credits | 16,015 | 24,840 | 6,775 |
Impact of Tax Reform Act | 52,449 | ||
Recognition of foreign deferred tax assets, net of U.S. impact | (45,751) | ||
Unrealizable foreign deferred tax assets | 24,176 | ||
Permanent differences | 180 | (104) | 309 |
Foreign tax credits expirations | 9,616 | 4,311 | 2,394 |
Increase/(decrease) in valuation allowance | (6,307) | (62,270) | (58,777) |
Other | (106) | ||
Total income tax expense (benefit) | $ 23,890 | $ (43,254) | $ 10,378 |
Income Taxes (Income Tax Years
Income Taxes (Income Tax Years Subject To Examination By Major Tax Jurisdictions) (Details) - Minimum [Member] | 12 Months Ended |
Dec. 31, 2019 | |
United States | |
Income Tax Examination [Line Items] | |
Income tax examination year under examination | 2009 |
Gabon [Member] | |
Income Tax Examination [Line Items] | |
Income tax examination year under examination | 2015 |
Crude Oil and Natural Gas Pro_2
Crude Oil and Natural Gas Properties and Equipment (Narrative) (Details) $ in Thousands, in Billions | Sep. 26, 2018USD ($) | Sep. 17, 2018USD ($) | Sep. 17, 2018XAF ( ) | Dec. 31, 2019USD ($)item | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 25, 2018USD ($) |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Production license agreement term extended by government | 5 years | ||||||
Deferred tax assets, basis difference in fixed assets | $ 26,590 | $ 38,479 | |||||
Deferred tax liabilities, basis difference in fixed assets | 18,600 | ||||||
Reduction in VAT receivable | 275 | (777) | $ (3,025) | ||||
VAT receivable, net of valuation allowance | 4,200 | ||||||
Allocated to proved leasehold cost | 22,500 | ||||||
Allocated to unproved leasehold cost | 13,700 | ||||||
Estimated costs of technical studies | 1,300 | ||||||
Estimated costs of technical studies, net | 400 | ||||||
Undeveloped Acreage | $ 23,771 | 23,771 | |||||
Monthly royalty rate, based on production at the published price | 13.00% | ||||||
Additional increase to working interest ownership, percent | 0.80% | ||||||
Inventory write-off | $ 0 | 0 | |||||
Etame Field [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Percent of participating interest | 33.575% | ||||||
Number of exploitation areas | item | 3 | ||||||
Period of agreement for exploitation areas | 10 years | ||||||
Number of contract extension periods | item | 2 | ||||||
Production license agreement term extended by government | 5 years | ||||||
Number of drilled wells required by agreement | item | 2 | ||||||
Number of appraisal wells required by agreement | item | 2 | ||||||
Block P Offshore Equatorial Guinea [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Deferred tax assets, basis difference in fixed assets | $ 18,600 | ||||||
Working interest ownership, percentage | 31.00% | ||||||
Undeveloped Acreage | $ 10,000 | ||||||
Period of development | 25 years | ||||||
Capitalized costs, signing bonus | $ 6,700 | ||||||
Capitalized costs, tax impact | 7,100 | ||||||
Undeveloped leasehold value | 10,000 | ||||||
Gabon [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Contractual commitment, gross | $ 65,000 | ||||||
Contractual obligation | 1,200 | $ 1,100 | $ 1,200 | $ 21,800 | |||
Cash paid for signing bonus, gross amount | $ 35,000 | ||||||
Payment of signing bonus, allocated to proved and unproved property | 11,800 | ||||||
Reduction in VAT receivable, gross amount | 25,000 | 14.1 | |||||
Reduction in VAT receivable | $ 8,400 | $ 4,200 | 4.7 | ||||
Accrued liabilities, end of drilling activities, gross amount | 5,000 | ||||||
Accrued liabilities, end of drilling activities | $ 1,700 | ||||||
Number of drilled wells required by agreement | item | 2 | ||||||
Number of appraisal wells required by agreement | item | 2 | ||||||
Working interest ownership, percentage | 7.50% | ||||||
Additional increase to working interest ownership, percent | 2.50% | ||||||
Inventory write-off | $ 400 | ||||||
Gabon DMO [Member] | Gabon [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Contractual obligation | $ 1,100 | 1,200 | |||||
PID And PIH [Member] | Gabon [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Contractual obligation | $ 2,200 | $ 1,900 | |||||
Prior Production Sharing Contract, Through September 17, 2018 [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Entitled percent for consortium after initial royalty percentage | 70.00% | ||||||
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Entitled percent for consortium after initial royalty percentage | 80.00% | ||||||
Production Sharing Contract, After September 16, 2028 [Member] | |||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||
Entitled percent for consortium after initial royalty percentage | 70.00% |
Derivatives and Fair Value (Nar
Derivatives and Fair Value (Narrative) (Details) $ in Millions | May 06, 2019$ / bblbbl | Dec. 31, 2019USD ($)bbl | Jun. 30, 2018bbl$ / bbl |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Barrels | 274,870 | ||
Benchmark of liability position, with required financial actions | $ | $ 10 | ||
Commodity Contract [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative assets | $ | $ 0.6 | ||
Quantity of barrels | 274,870 | ||
Commodity Contract, June 2018 Through June 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, average price per barrel | $ / bbl | 74 | ||
Quantity of barrels | 400,000 | ||
Commodity Contract, July 19 Through June 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, average price per barrel | $ / bbl | 66.70 | ||
Barrels | 500,000 |
Derivatives and Fair Value (Sum
Derivatives and Fair Value (Summary of Commodity Swaps) (Details) | 12 Months Ended |
Dec. 31, 2019$ / bblbbl | |
Barrels | 274,870 |
Commodity Contract January 2020 Through June 2020 [Member] | |
Barrels | 274,870 |
Weighted Average Fixed Price | $ / bbl | 66.70 |
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 | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, gain (loss) | $ (446) | $ 4,264 | $ (1,032) |
Realized Gain - Contract Settlements [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, gain (loss) | 2,439 | 744 | 195 |
Unrealized (Gain) Loss [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, gain (loss) | $ (2,885) | $ 3,520 | $ (1,227) |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations [Abstract] | ||||
Asset retirement obligation, revision of estimate | $ (400) | $ (379) | $ (6,527) | $ 703 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Summary of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations [Abstract] | ||||
Beginning balance | $ 14,816 | $ 20,163 | $ 18,612 | |
Accretion | 812 | 1,180 | 951 | |
Additions | 595 | |||
Acquisitions and dispositions | (103) | |||
Revisions | $ 400 | 379 | 6,527 | (703) |
Ending balance | $ 15,844 | $ 15,844 | $ 14,816 | $ 20,163 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||||
Oct. 31, 2019USD ($) | Jan. 31, 2019USD ($) | Apr. 30, 2018USD ($) | Dec. 31, 2019USD ($)$ / d$ / Boeitembbl | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Mar. 09, 2020item | Jul. 31, 2019USD ($) | Sep. 25, 2018USD ($) | |
Commitments And Contingencies [Line Items] | |||||||||
Liabilities, guarantees' fair value | $ 400 | $ 300 | |||||||
Production license agreement term extended by government | 5 years | ||||||||
Abandonment Funding | $ 11,371 | 11,571 | |||||||
Charter fee for production up to 20,000 BOPD | $ / Boe | 0.93 | ||||||||
Charter fee amount threshold | bbl | 20,000 | ||||||||
Charter fee for those bbls produced in excess of 20,000 BOPD | $ / Boe | 2.50 | ||||||||
Company's share of charter expense | $ 12,100 | 10,800 | $ 12,800 | ||||||
Estimated costs of technical studies | 1,300 | ||||||||
Estimated costs of technical studies, net | 400 | ||||||||
Loss contingency | $ 4,400 | ||||||||
Accrued liabilities and other | $ 29,773 | 14,138 | |||||||
Payment of other taxes | $ 1,300 | ||||||||
Gabon Tax Authority [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Tax examination settlement payment | $ 200 | ||||||||
Tax penalties | $ 200 | ||||||||
Potential Fees From Customs Audits [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Accrued liabilities and other | 1,300 | ||||||||
Gabon [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Discount | 15.00% | ||||||||
Contractual obligation | $ 1,200 | $ 1,100 | $ 1,200 | $ 21,800 | |||||
Number of drilled wells required by agreement | item | 2 | ||||||||
Number of appraisal wells required by agreement | item | 2 | ||||||||
Accrued liabilities, end of drilling activities, gross amount | $ 5,000 | ||||||||
Accrued liabilities, end of drilling activities | $ 1,700 | ||||||||
Number of technical studies required | item | 2 | ||||||||
Payment of joint venture audit settlement | $ 1,100 | $ 4,400 | |||||||
Additional percent of revenue for provisions | 1.00% | ||||||||
Percent of investment cost which are cost recoverable | 75.00% | ||||||||
Gabon [Member] | Gabon DMO [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Contractual obligation | $ 1,100 | $ 1,200 | |||||||
Gabon [Member] | PID And PIH [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Contractual obligation | $ 2,200 | $ 1,900 | |||||||
Etame Field [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Production license agreement term extended by government | 5 years | ||||||||
Number of drilled wells required by agreement | item | 2 | ||||||||
Number of appraisal wells required by agreement | item | 2 | ||||||||
Number of optional wells to drill | item | 4 | ||||||||
Number of optional well workovers | item | 3 | ||||||||
Day rate of drilling rig contract | $ / d | 75,000 | ||||||||
Number of contract extension periods | item | 2 | ||||||||
Etame Field [Member] | Subsequent Event [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Number of remaining well workovers | item | 2 | ||||||||
Full Charter Payment [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Contractual obligation | $ 56,275 | ||||||||
Abandonment cost related to annual funding | 61,800 | ||||||||
Full Charter Payment [Member] | Offshore Gabon [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Abandonment funding | 36,700 | ||||||||
VAALCO ENERGY, INC. [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Contractual obligation | 17,477 | ||||||||
VAALCO ENERGY, INC. [Member] | Offshore Gabon [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Abandonment funding | 11,400 | ||||||||
VAALCO ENERGY, INC. [Member] | Full Charter Payment [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Abandonment cost related to annual funding | $ 19,200 | ||||||||
Maximum [Member] | Etame Field [Member] | |||||||||
Commitments And Contingencies [Line Items] | |||||||||
Drilling commitment period | 1 year |
Commitments and Contingencies_3
Commitments and Contingencies (Estimated Obligations and Companies Share for the Annual Charter Payment) (Details) $ in Thousands | Dec. 31, 2019USD ($) |
VAALCO ENERGY, INC. [Member] | |
Estimated obligation and company share for annual charter payment | |
Annual charter payment, 2020 | $ 10,010 |
Annual charter payment, 2021 | 7,467 |
Annual charter payment, Total | 17,477 |
Full Charter Payment [Member] | |
Estimated obligation and company share for annual charter payment | |
Annual charter payment, 2020 | 32,233 |
Annual charter payment, 2021 | 24,042 |
Annual charter payment, Total | $ 56,275 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Joint owner obligation | $ 24,900 | ||
Future lease liabilities | $ 36,095 | ||
Rent expense, operating leases | $ 17,000 | $ 19,100 | |
Maximum [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lease terms | 45 months | ||
Minimum [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lease terms | 21 months |
Leases (Components of Lease Cos
Leases (Components of Lease Costs) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Leases [Abstract] | |
Operating lease cost | $ 16,428 |
Short-term lease cost | 3,470 |
Variable lease cost | 5,819 |
Total lease expense | 25,717 |
Lease costs capitalized | 3,653 |
Total lease cost | 29,370 |
Operating cash flows to operating leases | $ 19,229 |
Weighted-average remaining lease term | 2 years 8 months 12 days |
Weighted-average discount rate | 6.18% |
Leases (Lease Cost on Consolida
Leases (Lease Cost on Consolidated Statement of Operations) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Total lease expense | $ 28,236 |
Lease costs capitalized | 1,134 |
Total lease cost | 29,370 |
Production Expense [Member] | |
Total lease expense | 7,859 |
General and Administrative Expense [Member] | |
Total lease expense | 196 |
Lease Costs Billed To Joint Venture Owners [Member] | |
Total lease expense | $ 20,181 |
Leases (Schedule of Future Matu
Leases (Schedule of Future Maturities of Operating Lease Liabilities) (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
2020 | $ 13,655 |
2021 | 13,310 |
2022 | 9,130 |
Total lease payments | 36,095 |
Less: imputed interest | 2,734 |
Total lease liabilities | $ 33,361 |
Accrued Liabilities and Other_2
Accrued Liabilities and Other (Schedule of Accrued Liabilities and Other Balances) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Accrued Liabilities and Other [Abstract] | ||
Accrued accounts payable invoices | $ 4,650 | $ 4,669 |
Joint venture audit settlement | 3,322 | |
Gabon DMO, PID and PIH obligations | 3,314 | 3,145 |
Capital expenditures | 11,792 | 2,038 |
Stock appreciation rights | 2,638 | 1,007 |
Accrued wages and other compensation | 1,731 | 1,802 |
Other | 2,326 | 1,477 |
Total accrued liabilities and other | $ 29,773 | $ 14,138 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | Mar. 14, 2017 | Jun. 29, 2016 | Dec. 31, 2019 |
Debt Instrument [Line Items] | |||
Line Of Credit Facility Current Borrowing Capacity | $ 20 | ||
Term Loan [Member] | |||
Debt Instrument [Line Items] | |||
Loans payable | $ 15 | ||
Term Loan [Member] | London Interbank Offered Rate (LIBOR) | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate spread | 5.75% | ||
Additional Term Loan [Member] | |||
Debt Instrument [Line Items] | |||
Commitment fee percentage | 2.30% | ||
Borrowings | $ 4.2 | ||
Commitment fees, amount | $ 5 | ||
Line Of Credit Facility Current Borrowing Capacity | $ 5 | ||
Additional Term Loan [Member] | London Interbank Offered Rate (LIBOR) | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate spread | 5.75% |
Debt (Schedule of Interest Info
Debt (Schedule of Interest Information) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||
Interest expense related to debt, including commitment fees | $ (257) | $ (997) | |
Deferred finance costs amortization | (191) | (369) | |
Interest income | $ 733 | 270 | 7 |
Other interest expense not related to debt | 33 | (55) | |
Interest income (expense), net | $ 733 | $ (145) | $ (1,414) |
Various Debt Instruments [Member] | |||
Debt Instrument [Line Items] | |||
Average effective interest rate, excluding commitment fees | 7.09% | 6.72% |
Shareholders' Equity (Narrative
Shareholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 2 Months Ended | 7 Months Ended | 12 Months Ended | |||
Mar. 05, 2020 | Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | 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 | $ 3,911 | $ 51 | $ 20 | |||
2019 Repurchase Program [Member] | ||||||
Class of Stock [Line Items] | ||||||
Stock repurchase program, amount authorized | $ 10,000 | |||||
Stock repurchase program, period in force | 12 months | |||||
Shares repurchased | 2,067,188 | |||||
Average price per share | $ 1.81 | |||||
Price of shares repurchased | $ 3,700 | |||||
2019 Repurchase Program [Member] | Subsequent Event [Member] | ||||||
Class of Stock [Line Items] | ||||||
Shares repurchased | 44,368 | |||||
Average price per share | $ 1.99 | |||||
Price of shares repurchased | $ 100 |
Stock-Based Compensation and _3
Stock-Based Compensation and Other Benefit Plans (Narrative) (Details) $ / shares in Units, $ in Thousands | Jun. 06, 2019$ / sharesshares | May 10, 2019$ / sharesshares | Apr. 01, 2019$ / sharesshares | Feb. 28, 2019$ / sharesshares | Feb. 28, 2018$ / sharesshares | Dec. 31, 2019USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Stock options, authorized | shares | 68,241 | |||||||
Stock-based compensation | $ | $ 3,506 | $ 2,388 | $ 1,098 | |||||
Payments to settle stock appreciation rights | $ | 491 | 82 | ||||||
Cash proceeds from stock options exercised | $ | $ 300 | $ 500 | $ 39 | |||||
Options granted | shares | 923,000 | |||||||
Options granted, weighted average exercise price | $ 2.08 | $ 1.05 | $ 0.99 | |||||
Stock option granted, reduction ratio for numbers authorized | 1 | |||||||
Other benefit plans, cost | $ | $ 400 | $ 300 | $ 200 | |||||
Weighted average grant date fair value - ($/share) | $ 1.06 | $ 0.68 | $ 0.49 | |||||
Employees [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Awards, vesting period | 3 years | 3 years | 3 years | |||||
Options granted | shares | 257,228 | 44,163 | 622,140 | 494,941 | 1,162,930 | |||
Options granted, weighted average exercise price | $ 1.43 | $ 2.29 | $ 2.33 | $ 0.86 | ||||
Non-Employee Directors [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Options granted | shares | 175,644 | 465,950 | ||||||
Options granted, weighted average exercise price | $ 1.60 | |||||||
Stock Option [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Awards, vesting period | 5 years | |||||||
Total intrinsic value of options exercised | $ | $ 300 | $ 600 | $ 0 | |||||
Unrecognized compensation costs | $ | $ 300 | |||||||
Compensation costs expected to be recognized | 1 year 6 months | |||||||
Restricted Stock [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Awards, vesting period | 3 years | |||||||
Other awards granted | shares | 111,888 | 22,926 | 174,464 | 323,474 | 309,000 | |||
Other awards granted, weighted average exercise price | $ 1.43 | $ 2.29 | $ 2.33 | $ 0.86 | $ 2 | |||
Unrecognized compensation costs | $ | $ 200 | |||||||
Compensation costs expected to be recognized | 1 year 6 months | |||||||
Vest-date fair value | $ | $ 600 | $ 400 | $ 300 | |||||
Weighted average grant date fair value - ($/share) | $ 2 | $ 1.71 | $ 0.98 | |||||
Stock Appreciation Rights (SARs) [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Stock-based compensation | $ | $ 2,500 | |||||||
Award granted life | 5 years | 5 years | 5 years | |||||
Awards, vesting period | 3 years | 3 years | 3 years | 3 years | ||||
Other awards granted | shares | 196,892 | 951,699 | 2,373,411 | 1,148,000 | 1,049,528 | |||
Other awards granted, weighted average exercise price | $ 1.72 | $ 2.33 | $ 0.86 | $ 1.20 | ||||
Share-Based Compensation Arrangement By Share-Based Payment Award Life | 5 years | |||||||
Stock Appreciation Rights (SARs) [Member] | First Vesting Milestone [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Share-based compensation, vesting hurdle share price | 1.30 | |||||||
Stock Appreciation Rights (SARs) [Member] | Second Vesting Milestone [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Share-based compensation, vesting hurdle share price | 1.50 | |||||||
Stock Appreciation Rights (SARs) [Member] | Third Vesting Milestone [Member] | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Share-based compensation, vesting hurdle share price | $ 1.75 |
Stock-Based Compensation and _4
Stock-Based Compensation and Other Benefit Plans (Summary of Stock-Based Compensation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Total stock-based compensation | $ 3,506 | $ 2,388 | $ 1,098 |
Equity Award [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Total stock-based compensation | 985 | 820 | 977 |
Liability Award [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Total stock-based compensation | $ 2,521 | $ 1,568 | $ 121 |
Stock-Based Compensation and _5
Stock-Based Compensation and Other Benefit Plans (Stock Option Valuation Assumptions) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Valuation of the options granted | |||
Expected life in years | 3 years 2 months 12 days | 3 years 6 months | 3 years 2 months 12 days |
Average expected volatility | 73.00% | 71.00% | 73.00% |
Risk-free interest rate | 2.33% | 2.51% | 1.51% |
Weighted average grant date fair value - ($/share) | $ 1.06 | $ 0.68 | $ 0.49 |
Stock-Based Compensation and _6
Stock-Based Compensation and Other Benefit Plans (Stock Option Activity) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Stock-Based Compensation and Other Benefit Plans [Abstract] | |||
Number of Shares Underlying Options, Outstanding at January 1, 2019 | 2,601 | ||
Number of Shares Underlying Options, Granted | 923 | ||
Number of Shares Underlying Options, Exercised | (260) | ||
Number of Shares Underlying Options, Unvested shares forfeited | (306) | ||
Number of Shares Underlying Options, Vested shares expired | (124) | ||
Number of Shares Underlying Options, Outstanding at December 31, 2019 | 2,834 | 2,601 | |
Number of Shares Underlying Options, Exercisable at December 31, 2019 | 1,858 | ||
Weighted Average Exercise Price Per Share, Outstanding at January 1, 2019 | $ 1.54 | ||
Weighted Average Exercise Price Per Share, Granted | 2.08 | $ 1.05 | $ 0.99 |
Weighted Average Exercise Price Per Share, Exercised | 0.99 | ||
Weighted Average Exercise Price Per Share, Unvested shares forfeited | 1.50 | ||
Weighted Average Exercise Price Per Share, Vested shares expired | 6.70 | ||
Weighted Average Exercise Price Per Share, Outstanding at September 30, 2019 | 1.55 | $ 1.54 | |
Weighted Average Exercise Price Per Share, Exercisable at September 30, 2019 | $ 1.46 | ||
Weighted Average Remaining Contractual Term, Outstanding at September 30, 2019 | 2 years 9 months 7 days | ||
Weighted Average Remaining Contractual Term, Exercisable at September 30, 2019 | 2 years 4 months 2 days | ||
Aggregate Intrinsic Value, Outstanding at September 30, 2019 | $ 2,301 | ||
Aggregate Intrinsic Value, Exercisable at September 30, 2019 | $ 1,736 |
Stock-Based Compensation and _7
Stock-Based Compensation and Other Benefit Plans (Summary of Non Vested Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands | Jun. 06, 2019 | May 10, 2019 | Apr. 01, 2019 | Feb. 28, 2019 | Feb. 28, 2018 | Dec. 31, 2019 | Dec. 31, 2018 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Unvested awards forfeited | (541,000) | ||||||
Weighted Average Grant Price, Unvested awards forfeited | $ 1.41 | ||||||
Restricted Stock [Member] | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Outstanding at January 1, 2019 | 507,000 | ||||||
Awards granted | 111,888 | 22,926 | 174,464 | 323,474 | 309,000 | ||
Awards vested | (307,000) | ||||||
Unvested awards forfeited | (166,000) | ||||||
Outstanding at September 30, 2019 | 343,000 | 507,000 | |||||
Weighted Average Grant Price, Outstanding at January 1, 2019 | $ 0.91 | ||||||
Weighted Average Grant Price, Awards granted | $ 1.43 | $ 2.29 | $ 2.33 | $ 0.86 | 2 | ||
Weighted Average Grant Price, Awards vested | 1.12 | ||||||
Weighted Average Grant Price, Unvested awards forfeited | 1.29 | ||||||
Weighted Average Grant Price, Outstanding at September 30, 2019 | $ 1.52 | $ 0.91 | |||||
Stock Appreciation Rights (SARs) [Member] | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Outstanding at January 1, 2019 | 3,369,000 | ||||||
Awards granted | 196,892 | 951,699 | 2,373,411 | 1,148,000 | 1,049,528 | ||
Awards exercised | (558,000) | ||||||
Outstanding at September 30, 2019 | 3,418,000 | 3,369,000 | |||||
Exercisable at September 30, 2019 | 952,000 | ||||||
Weighted Average Grant Price, Awards granted | $ 1.72 | $ 2.33 | $ 0.86 | $ 1.20 | |||
Weighted Average Grant Price, Awards exercised | $ 1.04 | ||||||
Weighted Average Exercise Price Per Share, Exercisable at September 30, 2019 | 0.99 | ||||||
Weighted Average Exercise Price Per Share, Granted | 2.23 | ||||||
Weighted Average Exercise Price Per Share, Outstanding at December 31, 2017 | $ 1.30 | $ 0.96 | |||||
Term (in years), Outstanding at September 30, 2019 | 3 years 2 months 15 days | ||||||
Term (in years), Exercisable at September 30, 2019 | 2 years 6 months 21 days | ||||||
Aggregate Intrinsic Value, Outstanding at September 30, 2019 | $ 3,240 | ||||||
Aggregate Intrinsic Value, Exercisable at September 30, 2019 | $ 1,173 |
Selected Quarterly Financial _3
Selected Quarterly Financial Information (Summary of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Selected Quarterly Financial Information [Abstract] | |||||||||||
Revenues-crude oil and natural gas sales | $ 21,923 | $ 17,603 | $ 25,230 | $ 19,765 | $ 27,606 | $ 25,266 | $ 24,426 | $ 27,645 | $ 84,521 | $ 104,943 | $ 77,025 |
Total operating costs and expenses | 14,127 | 16,137 | 14,461 | 14,182 | 12,433 | 7,940 | 19,017 | 14,631 | 58,907 | 54,021 | 56,990 |
Operating income (loss) | 7,776 | 1,501 | 6,370 | 5,546 | 15,206 | 17,320 | 5,723 | 13,038 | 21,193 | 51,287 | 19,951 |
Income (loss) from continuing operations | 1,051 | (3,858) | (871) | 830 | 10,504 | 78,626 | 887 | 8,711 | (2,848) | 98,728 | 10,272 |
Income (loss) from discontinued operations, net of tax | (37) | (61) | (162) | 5,671 | (80) | (21) | (343) | (52) | 5,411 | (496) | (621) |
Net income (loss) | $ 1,014 | $ (3,919) | $ (1,033) | $ 6,501 | $ 10,424 | $ 78,605 | $ 544 | $ 8,659 | $ 2,563 | $ 98,232 | $ 9,651 |
Basic net income (loss) per share | $ 0.02 | $ (0.07) | $ (0.01) | $ 0.10 | $ 0.17 | $ 1.31 | $ 0.02 | $ 0.15 | $ 0.04 | $ 1.64 | $ 0.16 |
Diluted net income (loss) per share | 0.02 | (0.07) | (0.01) | 0.10 | 0.17 | 1.28 | 0.02 | 0.15 | 0.04 | 1.62 | 0.16 |
Basic income (loss) from continuing operations per share | 0.02 | (0.07) | (0.01) | 0.01 | 0.17 | 1.31 | 0.02 | 0.15 | (0.05) | 1.65 | 0.17 |
Diluted income (loss) from continuing operations per share | $ 0.02 | $ (0.07) | $ (0.01) | $ 0.01 | $ 0.17 | $ 1.28 | $ 0.02 | $ 0.15 | $ (0.05) | $ 1.63 | $ 0.17 |
Change in valuation allowance | $ (1,700) | $ 4,800 | $ 9,000 | ||||||||
Recognition of deferred tax assets | $ (66,600) |