UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
| | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
or
| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______ to _______
Commission File Number
VAALCO Energy, Inc.
(Exact name of registrant as specified in its charter)
| | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| Suite 700 | |
| (Address of principal executive offices) | (Zip code) |
(
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading symbol(s) | Name of each exchange on which registered |
| | | |
| Common Stock | EGY | London Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the past preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | | ☒ | |
| Non‑accelerated filer | ☐ | Smaller reporting company Emerging growth company | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
VAALCO ENERGY, INC. AND SUBSIDIARIES
Table of Contents
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
| As of March 31, 2023 | As of December 31, 2022 | |||||||
| (in thousands) | ||||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Restricted cash | ||||||||
| Receivables: | ||||||||
| Trade, net | ||||||||
| Accounts with joint venture owners, net of allowance for credit losses of $ million in both periods presented | ||||||||
| Foreign income taxes receivable | ||||||||
| Other, net of allowance for credit losses of $ and $ million, respectively | ||||||||
| Crude oil inventory | ||||||||
| Prepayments and other | ||||||||
| Total current assets | ||||||||
| Crude oil and natural gas properties, equipment and other - successful efforts method, net | ||||||||
| Other noncurrent assets: | ||||||||
| Restricted cash | ||||||||
| Value added tax and other receivables, net of allowance of $ million and $ million, respectively | ||||||||
| Right of use operating lease assets | ||||||||
| Right of use finance lease assets | ||||||||
| Deferred tax assets | ||||||||
| Abandonment funding | ||||||||
| Other long-term assets | ||||||||
| Total assets | $ | $ | ||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | $ | ||||||
| Accounts with joint venture owners | ||||||||
| Accrued liabilities and other | ||||||||
| Operating lease liabilities - current portion | ||||||||
| Finance lease liabilities - current portion | ||||||||
| Foreign income taxes payable | ||||||||
| Current liabilities - discontinued operations | ||||||||
| Total current liabilities | ||||||||
| Asset retirement obligations | ||||||||
| Operating lease liabilities - net of current portion | ||||||||
| Finance lease liabilities - net of current portion | ||||||||
| Deferred tax liabilities | ||||||||
| Other long-term liabilities | ||||||||
| Total liabilities | ||||||||
| Commitments and contingencies (Note 10) | ||||||||
| Shareholders’ equity: | ||||||||
| Preferred stock, $ par value; shares authorized, issued | ||||||||
| Common stock, $ par value; shares authorized, and shares issued, and shares outstanding, respectively | ||||||||
| Additional paid-in capital | ||||||||
| Accumulated other comprehensive income | ||||||||
| Less treasury stock, and shares, respectively, at cost | ( | ) | ( | ) | ||||
| Retained earnings | ||||||||
| Total shareholders' equity | ||||||||
| Total liabilities and shareholders' equity | $ | $ | ||||||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Unaudited)
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| (in thousands, except per share amounts) |
||||||||
| Revenues: |
||||||||
| Crude oil, natural gas and natural gas liquids sales |
$ | $ | ||||||
| Operating costs and expenses: |
||||||||
| Production expense |
||||||||
| Exploration expense |
||||||||
| Depreciation, depletion and amortization |
||||||||
| General and administrative expense |
||||||||
| Credit losses and other |
||||||||
| Total operating costs and expenses |
||||||||
| Other operating expense, net |
( |
) | ||||||
| Operating income |
||||||||
| Other income (expense): |
||||||||
| Derivative instruments gain (loss), net |
( |
) | ||||||
| Interest expense, net |
( |
) | ( |
) | ||||
| Other expense, net |
( |
) | ( |
) | ||||
| Total other expense, net |
( |
) | ( |
) | ||||
| Income from continuing operations before income taxes |
||||||||
| Income tax expense (benefit) |
( |
) | ||||||
| Income from continuing operations |
||||||||
| Loss from discontinued operations, net of tax |
( |
) | ( |
) | ||||
| Net income |
$ | $ | ||||||
| Other comprehensive income (loss) |
||||||||
| Currency translation adjustments |
( |
) | ||||||
| Comprehensive income |
$ | $ | ||||||
| Basic net income per share: |
||||||||
| Income from continuing operations |
$ | $ | ||||||
| Loss from discontinued operations, net of tax |
||||||||
| Net income per share |
$ | $ | ||||||
| Basic weighted average shares outstanding |
||||||||
| Diluted net income per share: |
||||||||
| Income from continuing operations |
$ | $ | ||||||
| Loss from discontinued operations, net of tax |
||||||||
| Net income per share |
$ | $ | ||||||
| Diluted weighted average shares outstanding |
||||||||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)
| Common Shares Issued |
Treasury Shares |
Common Stock |
Additional Paid-In Capital |
Accumulated Other Comprehensive Loss |
Treasury Stock |
Retained Earnings |
Total |
|||||||||||||||||||||||||
| (in thousands) |
||||||||||||||||||||||||||||||||
| Balance at January 1, 2023 |
( |
) | $ | $ | $ | $ | ( |
) | $ | $ | ||||||||||||||||||||||
| Shares issued - stock-based compensation |
( |
) | ||||||||||||||||||||||||||||||
| Stock-based compensation expense |
— | — | ||||||||||||||||||||||||||||||
| Common Shares Purchased |
( |
) | ( |
) | ( |
) | ||||||||||||||||||||||||||
| Treasury stock |
— | ( |
) | ( |
) | |||||||||||||||||||||||||||
| Dividend Distributions |
— | — | — | — | — | — | ( |
) | ( |
) | ||||||||||||||||||||||
| Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 |
— | — | ( |
) | ( |
) | ||||||||||||||||||||||||||
| Other comprehensive loss |
— | — | ( |
) | ( |
) | ||||||||||||||||||||||||||
| Net income |
— | — | ||||||||||||||||||||||||||||||
| Balance at March 31, 2023 |
( |
) | $ | $ | $ | $ | ( |
) | $ | $ | ||||||||||||||||||||||
| Common Shares Issued |
Treasury Shares |
Common Stock |
Additional Paid-In Capital |
Accumulated Other Comprehensive Loss |
Treasury Stock |
Retained Earnings |
Total |
|||||||||||||||||||||||||
| (in thousands) |
||||||||||||||||||||||||||||||||
| Balance at January 1, 2022 |
( |
) | $ | $ | $ | — | $ | ( |
) | $ | $ | |||||||||||||||||||||
| Shares issued - stock-based compensation |
( |
) | — | |||||||||||||||||||||||||||||
| Stock-based compensation expense |
— | — | — | |||||||||||||||||||||||||||||
| Treasury stock |
— | — | ( |
) | ( |
) | ||||||||||||||||||||||||||
| Dividend Distributions |
— | — | — | — | — | ( |
) | ( |
) | |||||||||||||||||||||||
| Net income |
— | — | ||||||||||||||||||||||||||||||
| Balance at March 31, 2022 |
( |
) | $ | $ | $ | — | $ | ( |
) | $ | $ | |||||||||||||||||||||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| (in thousands) |
||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Net income |
$ | $ | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Loss from discontinued operations, net of tax |
||||||||
| Depreciation, depletion and amortization |
||||||||
| Bargain purchase gain |
||||||||
| Deferred taxes |
( |
) | ||||||
| Unrealized foreign exchange loss |
||||||||
| Stock-based compensation |
||||||||
| Cash settlements paid on exercised stock appreciation rights |
( |
) | ( |
) | ||||
| Derivative instruments (gain) loss, net |
( |
) | ||||||
| Cash settlements paid on matured derivative contracts, net |
( |
) | ( |
) | ||||
| Cash settlements paid on asset retirement obligations |
( |
) | ||||||
| Credit losses and other |
||||||||
| Other operating loss, net |
||||||||
| Operational expenses associated with equipment and other |
( |
) | ||||||
| Change in operating assets and liabilities: |
||||||||
| Trade receivables |
( |
) | ||||||
| Accounts with joint venture owners |
( |
) | ||||||
| Other receivables |
( |
) | ( |
) | ||||
| Crude oil inventory |
( |
) | ( |
) | ||||
| Prepayments and other |
( |
) | ||||||
| Value added tax and other receivables |
( |
) | ( |
) | ||||
| Other long-term assets |
( |
) | ||||||
| Accounts payable |
( |
) | ( |
) | ||||
| Foreign income taxes receivable/payable |
||||||||
| Deferred tax liability |
( |
) | ||||||
| Accrued liabilities and other |
( |
) | ||||||
| Net cash provided by (used in) continuing operating activities |
( |
) | ||||||
| Net cash used in discontinued operating activities |
( |
) | ( |
) | ||||
| Net cash provided by (used in) operating activities |
( |
) | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Property and equipment expenditures |
( |
) | ( |
) | ||||
| Net cash used in continuing investing activities |
( |
) | ( |
) | ||||
| Net cash used in discontinued investing activities |
||||||||
| Net cash used in investing activities |
( |
) | ( |
) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
| Proceeds from the issuances of common stock |
||||||||
| Dividend distribution |
( |
) | ( |
) | ||||
| Treasury shares |
( |
) | ( |
) | ||||
| Payments of finance lease |
( |
) | ||||||
| Net cash used in continuing financing activities |
( |
) | ( |
) | ||||
| Net cash used in discontinued financing activities |
||||||||
| Net cash used in financing activities |
( |
) | ( |
) | ||||
| Effects of exchange rate changes on cash |
( |
) | ||||||
| NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH |
( |
) | ||||||
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD |
||||||||
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD |
$ | $ | ||||||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| (in thousands) |
||||||||
| Supplemental disclosure of cash flow information: |
||||||||
| Interest paid, net of amounts capitalized |
$ | $ | ||||||
| Supplemental disclosure of non-cash investing and financing activities: |
||||||||
| Property and equipment additions incurred but not paid at end of period |
$ | $ | ||||||
| Recognition of right-of-use finance lease assets and liabilities |
$ | $ | ||||||
See notes to condensed consolidated financial statements.
VAALCO ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND ACCOUNTING POLICIES
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids ("NGLs") properties. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and hold interests in two production sharing contracts ("PSCs") in Egypt. The Company has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, VAALCO has discontinued operations associated with activities in Angola, West Africa and Yemen.
The Company’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, VAALCO Energy, Inc. (UK Branch), VAALCO Energy (USA), Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC, TransGlobe Energy Corporation, TG Energy UK Ltd, TransGlobe Petroleum International Inc., TG Holdings Yemen Inc., TransGlobe West Bakr Inc., TransGlobe West Gharib Inc., TG Energy Marketing Inc., and TG NW Gharib Inc., TG S Ghazalat Inc.
These condensed consolidated financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.
These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, which includes a summary of the significant accounting policies.
On October 5, 2022, the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries (collectively, "OPEC+") announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022 through December 2023. On April 3, 2023, OPEC+ reaffirmed this reduction and announced additional voluntary reductions totaling 1.2 MMBbls through December 2023 by various members in addition to the 500 MBbls per day voluntary reduction already announced by Russia in February 2023. Included in the 1.2 MMBbls per day reduction was a voluntary reduction by the Gabonese government of 8 MBbls per day. The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives.
The average Brent crude oil price for the three months ended March 31, 2023 was $
During the year ended December 31, 2022 and continuing into 2023, the Company noticed that the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel and materials have increased. Management believes the ongoing war between Russia and Ukraine and the slowdown of the economy in China and their related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation and higher interest rates are impacting the global supply chain market.
While the current commodity price environment is still favorable and the Company has not experienced material disruptions to its operations as a result of COVID-19 or as result of other forces, including the Russia/Ukraine conflict or slowdown in the Chinese economy affecting the global market or further deteriorations of the global supply chain market may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil, natural gas and NGLs properties.
Principles of consolidation – The accompanying unaudited condensed consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.
Use of estimates – The preparation of the Financial Statements in conformity with GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of crude oil, natural gas and NGLs 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 becomes available.
Cash and cash equivalents – Cash and cash equivalents include deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks.
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 March 31, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in Gabon. Long-term amounts at March 31, 2023 and 2022 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows.
| As of March 31, | ||||||||
| 2023 | 2022 | |||||||
| (in thousands) | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Restricted cash - current | ||||||||
| Restricted cash - non-current | ||||||||
| Abandonment funding | ||||||||
| Total cash, cash equivalents and restricted cash | $ | $ | ||||||
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 unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 10 for further discussion.
On February 28, 2019, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar ("USD") denominated account advised the Company that the bank regulator required transfer of the funds to the Bank Of Central African States (BEAC) which is the Central Bank of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests since they were working on an abandonment fund common policy for the oil and gas Industry as well as the mining industry. As a result, the Company was able to make the annual abandonment funding payment for the years 2019 through 2022 totaling $
In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $
The Company is working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.
Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit losses associated with accounts with joint venture owners, see allowance for credit losses below.
Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.
Other receivables, net – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude oil produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into
On January 19, 2022, TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the "Eastern Desert") concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation ("EGPC"). The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new
For credit losses associated with other receivables, see allowance for credit losses below.
Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). For the allowance associated with VAT, see allowance for credit losses and other below. Since VAT is assessed under a foreign taxing authority, the allowance falls outside of the scope of the credit loss standard.
As of March 31, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $
Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates.
The Company estimates the current expected credit losses based primarily using an either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected.
The Company has identified the following types of financial assets that are within the scope of ASU 2016-13:
| • | Accounts receivable with joint venture owners; |
| • | Trade accounts receivables; |
| • | Other receivables |
As a result of adopting ASU 2016-13 on January 1, 2023, the Company recognized a $
Also on January 1, 2023, the Company transferred its $
During the three months ended March, 31, 2023, the Company recognized an additional $
With respect to the Company’s receivable from the refinery and TVA receivable balances, collection efforts, including remedies provided for in the contracts, are being pursued to collect overdue amounts owed to the Company. The Company is in ongoing discussions with the Ministry of the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances.
The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.
| Three Months Ended March 31, | ||||||
| 2023 | 2022 | |||||
| (in thousands) | ||||||
| Allowance for credit losses and other | ||||||
| Balance at beginning of period | $ | ( | ) | $ | ( | ) |
| Credit loss charges and other, net of receipts | ( | ) | ( | ) | ||
| Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 | ( | ) | ||||
| Foreign currency gain (loss) | ( | ) | ||||
| Balance at end of period | $ | ( | ) | $ | ( | ) |
Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored on the FSO at March 31, 2023 or the FPSO at March 31, 2022, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. The Company has made the decision to keep an inventory of crude in Egypt rather than perform direct sales in order to push for an export cargo during the second quarter of 2023. At March 31, 2023, the Company is in an underlift situation in Egypt.
Prepayments and Other – Included in “Prepayments and other” line item of the Company’s March 31, 2023 condensed consolidated balance sheet are $
Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the condensed 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 net realizable value.
Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs 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.
Capitalized Equipment Inventory – Capitalized equipment inventory represents the costs incurred in bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Capitalized equipment inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.
Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (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 block basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block 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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically years for office and miscellaneous equipment and to years for leasehold improvements.
Impairment – The Company reviews the crude oil, natural gas and NGLs producing properties for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly affects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 (as defined in the policy "Fair value" below) inputs that are based upon estimates 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, natural gas and NGLs 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, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil, natural gas and NGLs 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, Canada, Egypt and in Block P in Equatorial Guinea. See Note 7 for further discussion.
Purchase Accounting – On October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.
Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, if a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the condensed consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Finance lease liabilities – current portion” and “Finance lease liabilities – net of current portion” within the condensed consolidated balance sheets.
Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 13 for further discussion.
Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.
Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.
In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to continue its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s on the basis of the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the actual sales proceeds received.
Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.
Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 15 for further discussion.
Foreign currency transactions – The U.S. dollar is the functional currency of most of the Company’s foreign operating subsidiaries. However, in connection with the Company’s acquisition of TransGlobe, the Company acquired TransGlobe’s Canadian operations whose functional currency is the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries' functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Both realized and unrealized foreign exchange gain and losses are recorded within the condensed consolidated statements of operations and comprehensive income line item “Other (expense) income, net”.
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, natural gas and NGLs 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. The Company 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 changes 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 condensed consolidated financial position and results of operations. See Note 16 for further discussion.
Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of the Company's crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations and comprehensive income. See Note 8 for further discussion.
Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the internally developed present value of future cash flows model that underlies the fair-value measurement).
Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.
Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments and are considered Level 1 inputs. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.
| As of March 31, 2023 | |||||||||||||||||
| Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (in thousands) | |||||||||||||||||
| Assets | |||||||||||||||||
| Derivative asset | Prepayments and other | $ | $ | $ | $ | ||||||||||||
| $ | $ | $ | $ | ||||||||||||||
| Liabilities | |||||||||||||||||
| SARs liability | Accrued liabilities and other | $ | $ | $ | $ | ||||||||||||
| $ | $ | $ | $ | ||||||||||||||
| ` | As of December 31, 2022 | ||||||||||||||||
| Balance Sheet Line | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (in thousands) | |||||||||||||||||
| Assets | |||||||||||||||||
| Derivative asset | Prepayments and other | $ | $ | $ | $ | ||||||||||||
| $ | $ | $ | $ | ||||||||||||||
| Liabilities | |||||||||||||||||
| SARs liability | Accrued liabilities and other | $ | $ | $ | $ | ||||||||||||
| $ | $ | $ | $ | ||||||||||||||
Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.
Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above, as well as taxes other than income taxes.
Other comprehensive income – All of the Company’s other comprehensive income arises from TransGlobe's Canadian operations whose functional currency is the Canadian dollar. Translation gains and losses occur when translating the financial statements of non-U.S. functional currency operations to the USD. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the consolidated statements of operations and comprehensive income. Translations occur as follows:
| • | Income and expenses are translated at the date of the transaction. | |
| • | Assets and liabilities are translated at the prevailing rate on the balance sheet date. The exchange rate to convert Canadian dollars (“CAD") to US dollars (“USD”) at December 31, 2022 and at March 31, 2023 was |
2. NEW ACCOUNTING STANDARDS
Adopted
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016-13 is effective for Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As a smaller reporting company, through December 31, 2022, the Company was required to adopt the new standard for the fiscal years beginning after December 15, 2022, including interim periods within those fiscal years.
The Company adopted ASU 2016-13 ("ASC 326") on January 1, 2023 using the modified-retrospective approach. The modified-retrospective approach consists of applying the amendments in ASU 2016-03 through a cumulative-effect adjustment, if required, to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company’s current method and timing of recognizing credit losses is in accordance with ASC 326 and is consistent with the previous method of recognizing credit losses, except for one receivable, which now utilizes the Discounted Cash Flow method for computing its Expected Credit Loss ("ECL"). The Company recorded an ECL allowance of $
3. ACQUISITIONS AND DISPOSITIONS
TransGlobe Merger
On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding common shares of TransGlobe and TransGlobe became a direct wholly owned subsidiary of AcquireCo and an indirect wholly owned subsidiary of the Company pursuant to an arrangement agreement entered into by the Company, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”).
At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive
Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in the Arab Republic of Egypt and Canada. The Combined Company is a leading African-focused operator with a strong production and reserve base and a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. The transaction qualifies as a business combination under ASC 805, Business Combinations and the Company is the accounting acquiror. The purchase accounting for the business combination has not been completed.
During the three months ended March 31, 2023, the deferred tax liability in Egypt was increased by $
The actual impact of the Arrangement was an increase to “Crude oil, natural gas and NGLs sales” of $
| October 13, 2022 | Measurement Period Adjustment | October 13, 2022 (As Adjusted) | ||||||||||
| (in thousands) | (in thousands) | (in thousands) | ||||||||||
| Purchase Consideration | ||||||||||||
| Common stock issued to TransGlobe shareholders | $ | $ | — | $ | ||||||||
| October 13, 2022 | October 13, 2022 | October 13, 2022 | ||||||||||
| (in thousands) | (in thousands) | (in thousands) | ||||||||||
| Assets acquired: | ||||||||||||
| Cash | $ | $ | — | $ | ||||||||
| Wells, platforms and other production facilities | — | |||||||||||
| Equipment and other | — | |||||||||||
| Undeveloped acreage | — | |||||||||||
| Accounts receivable - trade | — | |||||||||||
| Accounts receivable - other | — | |||||||||||
| Accounts with joint venture owners | — | |||||||||||
| Right of use operating leases | — | |||||||||||
| Right of use financing leases | — | |||||||||||
| Prepayment and other | — | |||||||||||
| Liabilities assumed: | - | |||||||||||
| Asset retirement obligations | ( | ) | — | ( | ) | |||||||
| Accounts payable | ( | ) | — | ( | ) | |||||||
| Accrued liabilities and other | ( | ) | — | ( | ) | |||||||
| Operating lease liabilities - current portion | ( | ) | — | ( | ) | |||||||
| Financing lease liabilities - current portion | ( | ) | — | ( | ) | |||||||
| Operating lease liabilities - net of current portion | ( | ) | — | ( | ) | |||||||
| Financing lease liabilities - net of current portion | ( | ) | — | ( | ) | |||||||
| Deferred tax liabilities | ( | ) | ( | ) | ( | ) | ||||||
| Other long-term liabilities | ( | ) | — | ( | ) | |||||||
| Bargain purchase gain | ( | ) | ( | ) | ||||||||
| Total purchase price | $ | $ | — | $ | ||||||||
All assets and liabilities associated with TransGlobe, including crude oil, natural gas and NGLs properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, October 13, 2022, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using a weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and specific risk adjustment factors based on reserve category discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The purchase price allocation is preliminary pending final determination of the fair values of certain assets and liabilities, primarily the accounts receivable, asset retirement obligations, accounts payable and any contingencies, and any related tax impacts. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, an initial $
The unaudited pro forma results presented below have been prepared to give the effect of the TransGlobe Arrangement discussed above on the Company’s results for the three months ended March 31, 2022, as if the Arrangement had been consummated on January 1, 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the TransGlobe Arrangement had been completed on such date or project the Company’s results of operations for any future date or period.
| Three Months Ended March 31, | |||||
| 2022 | |||||
| (in thousands) | |||||
| Pro forma (unaudited): | |||||
| Crude oil, natural gas and natural gas liquids sales | $ | (a) | |||
| Operating income | $ | (b) | |||
| Net income | $ | (c) | |||
| Basic net income per share: | $ | ||||
| Basic weighted average shares outstanding | |||||
| Diluted net income per share: | $ | ||||
| Diluted weighted average shares outstanding | |||||
| (a) | The unaudited pro forma net revenues associated with Crude oil, natural gas and natural gas liquids sales have been adjusted for shipping and handling costs based on the Company’s historical policy and revenue recognition is based on the Company’s working interest, less royalties, the entitlement method. |
| (b) | The unaudited pro forma operating income for the three months ended March 31, 2022 removes the $ |
| (c) | The unaudited pro forma net income for the year ended March 31, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense. |
Discontinued Operations - Angola and Yemen
In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was
As part of the Arrangement with TransGlobe, the Company acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S-1. In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S-1. The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income. The Company segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three months ended March 31, 2023, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.
4. SEGMENT INFORMATION
The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s
Segment activity of continuing operations for the three months ended March 31, 2023 and 2022 as well as long-lived assets and segment assets at March 31, 2023 and December 31, 2022 are as follows:
| Three Months Ended March 31, 2023 |
||||||||||||||||||||||||
| (in thousands) |
Gabon |
Egypt |
Canada |
Equatorial Guinea |
Corporate and Other |
Total |
||||||||||||||||||
| Revenues: |
||||||||||||||||||||||||
| Crude oil, natural gas and natural gas liquids sales |
$ | $ | $ | $ | $ | $ | ||||||||||||||||||
| Operating costs and expenses: |
||||||||||||||||||||||||
| Production expense |
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| Exploration expense |
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| Depreciation, depletion and amortization |
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| General and administrative expense |
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| Credit losses and other |
||||||||||||||||||||||||
| Total operating costs and expenses |
||||||||||||||||||||||||
| Operating income (loss) |
( |
) | ( |
) | ||||||||||||||||||||
| Other income (expense): |
||||||||||||||||||||||||
| Derivative instruments gain, net |
— | — | — | |||||||||||||||||||||
| Interest (expense) income, net |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||||||||||
| Other income (expense), net |
( |
) | ( |
) | ( |
) | ||||||||||||||||||
| Total other expense, net |
( |
) | ( |
) | ( |
) | ( |
) | ( |
) | ( |
) | ||||||||||||
| Income (loss) from continuing operations before income taxes |
( |
) | ( |
) | ||||||||||||||||||||
| Income tax expense |
||||||||||||||||||||||||
| Income (loss) from continuing operations |
( |
) | ( |
) | ||||||||||||||||||||
| Loss from discontinued operations, net of tax |
( |
) | ( |
) | ||||||||||||||||||||
| Net income (loss) |
$ | $ | $ | $ | ( |
) | $ | ( |
) | $ | ||||||||||||||
| Consolidated capital expenditures |
$ | $ | $ | $ | $ | $ | ||||||||||||||||||
| Three Months Ended March 31, 2022 |
||||||||||||||||
| (in thousands) |
Gabon |
Equatorial Guinea |
Corporate and Other |
Total |
||||||||||||
| Revenues: |
||||||||||||||||
| Crude oil and natural gas sales |
$ | $ | $ | $ | ||||||||||||
| Operating costs and expenses: |
||||||||||||||||
| Production expense |
||||||||||||||||
| Exploration expense |
||||||||||||||||
| Depreciation, depletion and amortization |
||||||||||||||||
| General and administrative expense |
||||||||||||||||
| Credit losses and other |
||||||||||||||||
| Total operating costs and expenses |
||||||||||||||||
| Other operating expense, net |
( |
) | ( |
) | ||||||||||||
| Operating income |
( |
) | ( |
) | ||||||||||||
| Other income (expense): |
||||||||||||||||
| Derivative instruments loss, net |
( |
) | ( |
) | ||||||||||||
| Interest (expense) income, net |
( |
) | ( |
) | ||||||||||||
| Other expense, net |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
| Total other expense, net |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
| Income from continuing operations before income taxes |
( |
) | ( |
) | ||||||||||||
| Income tax (benefit) expense |
( |
) | ( |
) | ||||||||||||
| Income (loss) from continuing operations |
( |
) | ( |
) | ||||||||||||
| Loss from discontinued operations, net of tax |
( |
) | ( |
) | ||||||||||||
| Net income (loss) |
$ | $ | ( |
) | $ | ( |
) | $ | ||||||||
| Consolidated capital expenditures |
$ | $ | $ | $ | ||||||||||||
| (in thousands) |
Gabon |
Egypt |
Canada |
Equatorial Guinea |
Corporate and Other |
Total |
||||||||||||||||||
| Long-lived assets from continuing operations: |
||||||||||||||||||||||||
| As of March 31, 2023 |
$ | $ | $ | $ | $ | $ | ||||||||||||||||||
| As of December 31, 2022 (1) |
$ | $ | $ | $ | $ | |||||||||||||||||||
(1) - Includes assets acquired in the TransGlobe acquisition
| (in thousands) |
Gabon |
Egypt |
Canada |
Equatorial Guinea |
Corporate and Other |
Total |
||||||||||||||||||
| Total assets from continuing operations: |
||||||||||||||||||||||||
| As of March 31, 2023 |
$ | $ | $ | $ | $ | $ | ||||||||||||||||||
| As of December 31, 2022 (1) |
$ | $ | $ | $ | $ | |||||||||||||||||||
(1) - Includes assets acquired in the TransGlobe acquisition
Information about the Company’s most significant customers
The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The Company was previously party to a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through July 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. This COSPA has been terminated.
As discussed further in Note 11, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an initial aggregate maximum principal amount available of up to $
For the three months ended March 31, 2023 sales of crude oil to Glencore made up
5. EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.
A reconciliation of reported net income to net income used in calculating EPS as well as a reconciliation from basic to diluted shares follows:
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| (in thousands) |
||||||||
| Net income (loss) (numerator): |
||||||||
| Income (loss) from continuing operations |
$ | $ | ||||||
| Income from continuing operations attributable to unvested shares |
( |
) | ||||||
| Numerator for basic |
||||||||
| Loss from continuing operations attributable to unvested shares |
( |
) | ||||||
| Numerator for dilutive |
$ | $ | ||||||
| Loss from discontinued operations, net of tax |
$ | ( |
) | $ | ( |
) | ||
| Loss from discontinued operations attributable to unvested shares |
||||||||
| Numerator for basic |
( |
) | ( |
) | ||||
| (Income) loss from discontinued operations attributable to unvested shares |
||||||||
| Numerator for dilutive |
$ | ( |
) | $ | ( |
) | ||
| Net income (loss) |
$ | $ | ||||||
| Net income attributable to unvested shares |
( |
) | ( |
) | ||||
| Numerator for basic |
||||||||
| Net (income) loss attributable to unvested shares |
( |
) | ||||||
| Numerator for dilutive |
$ | $ | ||||||
| Weighted average shares (denominator): |
||||||||
| Basic weighted average shares outstanding |
||||||||
| Effect of dilutive securities |
||||||||
| Diluted weighted average shares outstanding |
||||||||
| Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive |
||||||||
6. REVENUE
Gabon
Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs or COSMAs. COSPAs or COSMAs 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 or COSMAs. See Note 4 under “Information about the Company’s most significant customers” for further discussion.
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 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
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e., the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as operator, 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 volumes sold exceeded the Company’s ownership interest. However, under the COSMA, each coventurer is responsible for invoicing Glencore their respective ownership interest in the final volumes.
For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.
In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame 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
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 the corporate income tax liability may be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations and comprehensive income, 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 as a current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, i.e., the period in which it lifts the crude oil.
With respect to the government’sshare 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 and comprehensive income, 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 are 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 Company has a $
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.
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| Revenues from customer contracts: |
(in thousands) |
|||||||
| Sales under the COSPA or COSMA |
$ | $ | ||||||
| Other items reported in revenue not associated with customer contracts: |
||||||||
| Carried interest recoupment |
||||||||
| Royalties |
( |
) | ( |
) | ||||
| Net revenues |
$ | $ | ||||||
Egypt
Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs"). EGPC and the Company’s subsidiary, TransGlobe Petroleum International (“TPI”), each own a
Customer sales generally occur on a daily basis when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. Direct sales to EGPC are considered complete when oil is delivered to EGPC storage facility. When sales are made through cargo lifting, the performance obligations are normally satisfied either when the oil is delivered to the export facility location or when the oil is delivered to its ultimate destination, as specified in the contract. Regardless of the type of sales, there is a single performance obligation (delivering crude oil to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.
Revenues associated with the sales of the Company’s crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, the Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of profit oil or excess cost oil which is discussed below.
Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned
With respect to Egyptian income taxes, which are the Company’s liability under the terms of the Merged Concession Agreement, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense for reporting purposes.
EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30-day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Direct sales to EGPC are normally settled two to four weeks from delivery.
In some instances TPI will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances, TPI can be in an overlift or underlift position. Regardless of being in an over lift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and TPI will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable.
The following table presents revenues in Egypt from contracts with customers:
| Three Months Ended March 31, |
||||
| 2023 |
||||
| Revenues from customer contracts: |
(in thousands) |
|||
| Gross sales |
$ | |||
| Royalties |
( |
) | ||
| Selling costs |
( |
) | ||
| Net revenues |
$ | |||
Canada
Revenues from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. 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. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are measured at the transaction price that the Company expects to be entitled in exchange for transferring promised goods to a customer and is determined based at the fair value of the consideration received. VAALCO pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. For reporting purposes, the Company records revenues net of royalties.
Customer sales generally occur on a daily basis when crude oil, natural gas, condensate or NGL’s are sold, normally via pipeline, to a delivery point. Regardless of the type of sales, there is a single performance obligation (delivering crude oil, natural gas, condensate or NGL’s to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.
Settlement of accounts receivable in Canada occur on the 25th of the following month after production.
The following table presents revenues in Canada from contracts with customers:
| Three Months Ended March 31, |
||||
| 2023 |
||||
| Revenues from customer contracts: |
(in thousands) |
|||
| Oil revenue |
$ | |||
| Gas revenue |
||||
| NGL revenue |
||||
| Royalties |
( |
) | ||
| Net revenues |
$ | |||
7. CRUDE OIL, NATURAL GAS and NGLs PROPERTIES AND EQUIPMENT
The Company’s crude oil, natural gas and NGLs properties and equipment is comprised of the following:
| As of March 31, 2023 |
As of December 31, 2022 |
|||||||
| (in thousands) |
||||||||
| Crude oil and natural gas properties and equipment - successful efforts method: |
||||||||
| Wells, platforms and other production facilities |
$ | $ | ||||||
| Work-in-progress |
||||||||
| Undeveloped acreage |
||||||||
| Equipment and other |
||||||||
| Accumulated depreciation, depletion, amortization and impairment |
( |
) | ( |
) | ||||
| Net crude oil and natural gas properties, equipment and other |
$ | $ | ||||||
Etame Marin Block PSC
On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received a Presidential Decree for an extension (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a
The PSC Extension extends the term to operate until September 17, 2028. The PSC Extension also grants the Etame Consortium the right for additional extension periods of years each.
In accordance with the Etame Marin block PSC, the Etame Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Under the PSC Extension, the Cost Recovery Percentage increased to
Egypt PSCs
On January 20, 2022, the Company announced a fully executed Merged Concession Agreement with EGPC that merged the existing Eastern Desert concessions with a
The Merged Concession Agreement contains minimum financial work commitments of $
The Egyptian PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs. Each PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production less cost oil) is shared between the government and the contractor as defined in the specific PSC. The Egyptian PSCs do not contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the contractor's sales volumes. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.
The following table summarizes the Company's Egyptian PSC terms for the first tranche(s) of production for each block. The contracts have different terms for production levels above the first tranche, which are unique to each contract. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche. The Company is the contractor in all of the Company's PSCs.
| Block |
Merged Concession |
South Ghazalat |
||||||
| Year acquired (1) |
|
|
||||||
| Expiry date |
2035 |
2039 |
||||||
| Extensions |
||||||||
| Exploration |
N/A | N/A | ||||||
| Development |
|
|
||||||
| Production Tranche (MBopd) |
||||||||
| Maximum cost oil |
% | % | ||||||
| Excess cost oil - Contractor |
% | % | ||||||
| Depreciation per quarter |
||||||||
| Operating |
% | % | ||||||
| Capital |
% | % | ||||||
| Production Sharing Oil: |
||||||||
| Contractor |
%* | % | ||||||
| Government |
%* | % | ||||||
(1) - Represents the year acquired by TransGlobe, prior to the Arrangement.
| *Merged Concession profit oil is set on a scale according to average Brent price and production: |
||||||||||||||
| Crude oil produced (MBopd) |
||||||||||||||
| Brent Price ($/bbl) |
Less than or equal to 5 MBopd |
More than 5 MBopd and less than or equal to 10 MBopd |
More than 10 MBopd and less than or equal to 15 MBopd |
More than 15 MBopd and less than or equal to 25 MBopd |
More than 25 MBopd |
|||||||||
| Government % |
Contractor % |
Government % |
Contractor % |
Government % |
Contractor % |
Government % |
Contractor % |
Government % |
Contractor % |
|||||
| Less than or equal to $40/bbl |
|
|
|
|
|
|
|
|
|
|
||||
| More than $40/bbl and less than or equal to $60/bbl |
|
|
|
|
|
|
|
|
|
|
||||
| More than $60/bbl and less than or equal to $80/bbl |
|
|
|
|
|
|
|
|
|
|
||||
| More than $80/bbl and less than or equal to $100/bbl |
|
|
|
|
|
|
|
|
|
|
||||
| More than $100/bbl |
|
|
|
|
|
|
|
|
|
|
||||
Equatorial Guinea PSC
With the approval of the plan of development in September, 2022, the Block P production sharing contract provides for a development and production period of
Proved Properties
The Company reviews the crude oil, natural gas and NGLs 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, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.
There was no triggering event in the three months ended March 31, 2023 that would cause the Company to believe the value of crude oil, natural gas and NGLs producing properties should be impaired. Factors considered included higher forward prices from December 31, 2022 and capital expenditures in the period related to its reserves in Gabon, Egypt and Canada.
Undeveloped Leasehold Costs
Equatorial Guinea
VAALCO acquired a
The Company has completed a feasibility study of the development concept of the Venus discovery on Block P. On September 16, 2022, the EG MMH approved the submitted plan of development. Final documents to affect the plan of development are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and was approved effective November 16, 2022. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with updated participating interest. Execution of the Venus development plan has been initiated. The Block P production sharing contract provides for a development and production period of
Gabon
As a result of the PSC extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $
Egypt and Canada
In connection with the TransGlobe acquisition discussed under Note 3, the Company added $
Capitalized Equipment Inventory
Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating expense, net” line item of the unaudited condensed consolidated statements of operations and comprehensive income but were not material for the three months ended March 31, 2023 and 2022.
8. DERIVATIVES AND FAIR VALUE
The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the Company’s exposure to price fluctuations. See the table below for the list of outstanding contracts as of March 31, 2023:
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||||||||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||||||||
| April 2023 - June 2023 |
Collars |
Dated Brent |
$ | $ | ||||||||||
While these derivative instruments are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes. In connection with the RBL facility entered in May 2022, the Company is required to hedge a portion of its anticipated oil production at the time the Company draws down on the borrowing base.
The derivative instruments are measured at fair value using the Income Method. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the derivative instrument contracts’ fair value includes the impact of the counterparty’s non-performance risk.
To mitigate counterparty risk, the Company enters into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
At times, the Company’s counterparties require that it post collateral for changes in the net fair value of the derivative contracts. This cash collateral is reported in the line item "Restricted cash" on the unaudited condensed consolidated balance sheets.
The following table sets forth the loss on derivative instruments on the Company’s unaudited condensed consolidated statements of operations and comprehensive income:
| Three Months Ended March 31, |
||||||||||
| Derivative Item |
Statements of Operations Line |
2023 |
2022 |
|||||||
| (in thousands) |
||||||||||
| Commodity derivatives |
Cash settlements paid on matured derivative contracts, net |
$ | ( |
) | $ | ( |
) | |||
| Unrealized gain (loss) |
( |
) | ||||||||
| Derivative instruments gain (loss), net |
$ | $ | ( |
) | ||||||
Subsequent Event
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||
| July 2023 - September 2023 |
Collars |
Dated Brent |
$ | $ | ||||
9. CURRENT ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other balances were comprised of the following:
| As of March 31, 2023 |
As of December 31, 2022 |
|||||||
| (in thousands) |
||||||||
| Accrued accounts payable invoices |
$ | $ | ||||||
| Gabon DMO, PID and PIH obligations |
||||||||
| Capital expenditures |
||||||||
| Stock appreciation rights – current portion |
||||||||
| Accrued wages and other compensation |
||||||||
| ARO Obligation |
||||||||
| Egypt modernization payments |
||||||||
| Excess cost oil payable |
||||||||
| Other |
||||||||
| Total accrued liabilities and other |
$ | $ | ||||||
10. COMMITMENTS AND CONTINGENCIES
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, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, an abandonment study was done and the estimate used for this purpose is approximately $
In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $
FPSO charter
In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for -year periods beyond September 2020. These elections were made, and the charter was extended through September 2022. On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 and ratified certain decommissioning and demobilization items associated with exiting the contract.
Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $
Regulatory and Joint Interest Audits and Related Matters
The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the Company’s petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the Company’s joint operating agreements.
In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years through 2014. The Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the newly appointed representatives to resolve the audit findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.
Between 2019 and 2021, the government of Gabon conducted an audit of the operations in Gabon, covering the years and 2016. The Company received the findings from this audit and has responded to the audit findings and are working with the government of Gabon on the results of the findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.
Dividend Policy
On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy.
On , the Company's board of directors declared a quarterly cash dividend of $
In connection with the RBL facility, discussed in Note 11, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Share Buyback Program
On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $
The following table shows the repurchases of equity securities related to the share repurchase program after January 1, 2023 through March 31, 2023:
| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Programs | Maximum Amount that May Yet Be Used to Purchase Shares Under the Program | ||||||||||||
| January 1, 2023 - January 31, 2023 | $ | $ | ||||||||||||||
| February 1, 2023 - February 28, 2023 | $ | $ | ||||||||||||||
| March 1, 2023 - March 31, 2023 | $ | $ | ||||||||||||||
| Total | ||||||||||||||||
The following table shows the repurchases of equity securities related to the share repurchase program after April 1, 2023 through May 9, 2023:
| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Programs | Maximum Amount that May Yet Be Used to Purchase Shares Under the Program | ||||||||||||
| April 1, 2023 - April 30, 2023 | $ | $ | ||||||||||||||
| May 1, 2023 - May 8, 2023 | $ | $ | ||||||||||||||
| Total | ||||||||||||||||
In connection with the RBL facility, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.
The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, the Company's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, the Company’s third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the Plan.
Merged Concession Agreement
On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed concession agreement "Merged Concession Agreement" with the Egyptian General Petroleum Corporation (“EGPC”) that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $
The Company also has minimum financial work commitments of $
As the Merged Concession Agreement is effective as of February 1, 2020, there will be effective date adjustment owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date. In accordance with GAAP, the Company has recognized a receivable in connection with the effective date adjustment of $
Government Related Receivables
Under the Article 35 of the Etame PSC, the Company can be required to contribute to meeting the domestic market needs of Gabon by delivering to the Government, or another entity designated by the Government, an amount of its crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In October 2021, the Company was notified by the Government to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. In exchange, the Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered.
Since the crude oil produced by the Company is not compatible with the crude oil requirements of the refinery, the Company entered into two contracts (buy/sell arrangements) to fulfill its domestic market needs obligation under the Etame PSC. One contract is to purchase oil from another provider (currently Perenco – the supplier) that produces the compatible oil to meet the needs of the refinery and another contract with the refinery itself (currently Sogara -the buyer and state designee) to deliver the crude oil to the Government.
In November 2022, a receivable from Sogara became past due and the Company has not received payments from the refinery since November 2022. At March 31, 2023 the amount due to the Company from the refinery is $
11. DEBT
As of March 31, 2023 and December 31, 2022, the Company had
RBL Facility
On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $
The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves in Gabon and a portion of the Company's proved undeveloped reserves in Gabon. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.
Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i)
Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i)
The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed and (ii) consolidated cash and cash equivalents shall not be lower than $
The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).
Deferred financing costs incurred in connection with securing the Facility were $
ATB Facility
In connection with the Arrangement with TransGlobe in October 2022, and prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owed under TransGlobe’s credit facility with ATB Financial (the "ATB Facility"), representing approximately Canadian $
12. LEASES
Under the leasing standard that became effective January 1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.
Practical Expedients
The Company elected to use all the practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1, 2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption.
Operating leases
The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and equipment and a drilling rig used in the Company’s Egyptian operations.. The duration for these agreements ranges from
The marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.
Financing leases
The Company is currently a party to several financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The duration for these agreements ranges from
All leases
For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it will extend the lease beyond the initial lease term. When the Company believes it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.
For the three months ended March 31, 2023 and 2022, the components of the lease costs and the supplemental information were as follows:
| Three Months Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| Lease cost: | (in thousands) | |||||||
| Finance lease cost (1) | $ | $ | ||||||
| Operating lease cost | ||||||||
| Short-term lease cost (2) | ||||||||
| Variable lease cost (3) | ||||||||
| Total lease expense | ||||||||
| Lease costs capitalized | ||||||||
| Total lease costs | $ | $ | ||||||
| Three Months Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| Other information: | ||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | ||||||||
| Financing cash flows attributable to finance leases (in thousands) | $ | $ | ||||||
| Weighted-average remaining lease term (in years) | ||||||||
| Weighted-average discount rate | % | % | ||||||
| Operating cash flows attributable to operating leases (in thousands) | $ | $ | ||||||
| Weighted-average remaining lease term (in years) | ||||||||
| Weighted-average discount rate | % | % | ||||||
| (1) | Represents depreciation and interest associated with financing leases. |
| (2) | Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded. |
| (3) | Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts. |
The table below describes the presentation of the total lease cost on the Company’s unaudited condensed consolidated statements of operations and comprehensive income. As discussed above, the Company’s joint venture owners are required to reimburse the Company for their share of certain expenses, including certain lease costs.
| Three Months Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| (in thousands) | ||||||||
| Finance lease cost | $ | $ | ||||||
| Production expense | ||||||||
| General and administrative expense | ||||||||
| Lease costs billed to the joint venture owners | ||||||||
| Total lease expense | ||||||||
| Lease costs capitalized | ||||||||
| Total lease costs | $ | $ | ||||||
The following table describes the future maturities of the Company’s lease liabilities at March 31, 2023:
| Operating Leases | Finance Leases | |||||||
| Year | (in thousands) | |||||||
| 2023 | $ | $ | | |||||
| 2024 | ||||||||
| 2025 | ||||||||
| 2026 | ||||||||
| 2027 | ||||||||
| Thereafter | ||||||||
| Less: imputed interest | ||||||||
| Total lease liabilities | $ | $ | ||||||
Under the joint operating agreements, other joint venture owners are obligated to fund $
13. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations:
| (in thousands) | As of March 31, 2023 | As of December 31, 2022 | ||||||
| Beginning balance | $ | $ | ||||||
| Accretion | ||||||||
| Additions | ||||||||
| Revisions | ( | ) | ||||||
| Settlements | ( | ) | ( | ) | ||||
| Foreign currency gain (loss) | ( | ) | ||||||
| Ending balance | $ | $ | ||||||
Accretion is recorded in the line item “Depreciation, depletion and amortization” in the unaudited condensed consolidated statements of operations and comprehensive income.
In connection with the TransGlobe Arrangement in October 2022, as discussed in Note 3, the Company added million of ARO for the future abandonment and reclamation costs of the Canadian assets. The Egypt concessions have
With relation to the end of the FPSO contract in October 2022, the Company incurred decommissioning settlement fees totaling $
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 prepared in November 2021. As a result of the expected timing of the end of the FPSO contract, included in the line item "Accrued liabilities and other" in the unaudited condensed consolidated balance sheet is $
In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.
In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor may be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism. At December 31, 2022,
The Company provides for asset retirement obligations on all of its Canadian operations based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The estimated ARO liability for Canada includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as using inflation factors and discount rates in order to calculate the amount of the ARO liability.
14. SHAREHOLDERS’ EQUITY
Common stock
On October 13, 2022, in connection with the closing of the Arrangement, (i) the total number of authorized shares of common stock of the Company was increased from
Preferred stock
Authorized preferred stock consists of
Treasury stock
On November 1, 2022, the Company announced that the board of directors formally ratified and approved a share buyback program. The Plan provides for an aggregate purchase of currently outstanding common stock up to $
The below table shows the repurchases of the Company's equity securities during the three months ended March 31, 2023:
| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Programs | Maximum Amount that May Yet Be Used to Purchase Shares Under the Program | ||||||||||||
| January 1, 2023 - January 31, 2023 | $ | $ | ||||||||||||||
| February 1, 2023 - February 28, 2023 | $ | $ | ||||||||||||||
| March 1, 2023 - March 31, 2023 | $ | $ | ||||||||||||||
| Total | ||||||||||||||||
For the majority of restricted stock awards granted by the Company, the number of shares issued to the participant on the vesting date are net of shares withheld to meet applicable tax withholding requirements. In addition, when options are exercised, the participant may elect to remit shares to the Company to cover the tax liability and the cost of the exercised options. When this happens, the Company adds these shares to treasury stock and pays the taxes on the participant’s behalf.
Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in the Company's financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 15 for further discussion.
15. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS
The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s board of directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which
For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the three months ended March 31, 2023, the Company settled in cash $
| Three Months Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| (in thousands) | ||||||||
| Stock-based compensation - equity awards | $ | $ | ||||||
| Stock-based compensation - liability awards | ( | ) | ||||||
| Total stock-based compensation | $ | $ | ||||||
Stock options and performance shares
Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors that is generally a -year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.
The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option.
For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.
During the three months ended March 31, 2022, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo.
| Three Months Ended March 31, | ||||
| 2022 | ||||
| Weighted average exercise price - ($/share) | $ | |||
| Expected life in years | ||||
| Average expected volatility | % | |||
| Risk-free interest rate | % | |||
| Expected dividend yield | % | |||
| Weighted average grant date fair value - ($/share) | $ | |||
Stock option activity associated with the Monte Carlo model for the three months ended March 31, 2023 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, 2023 | $ | |||||||||||||||
| Granted | ||||||||||||||||
| Exercised | ( | ) | ( | ) | ||||||||||||
| Unvested shares forfeited | ||||||||||||||||
| Vested shares expired | ||||||||||||||||
| Outstanding at March 31, 2023 | $ | $ | ||||||||||||||
| Exercisable at March 31, 2023 | $ | $ | ||||||||||||||
Stock option activity associated with the Black-Scholes model for the three months ended March 31, 2023 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, 2023 | $ | |||||||||||||||
| Granted | ||||||||||||||||
| Exercised | ( | ) | ( | ) | ||||||||||||
| Unvested shares forfeited | ||||||||||||||||
| Vested shares expired | ||||||||||||||||
| Outstanding at March 31, 2023 | $ | $ | ||||||||||||||
| Exercisable at March 31, 2023 | $ | $ | ||||||||||||||
As a result of tax withholding on options exercised,
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a -year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). The vesting of the restricted stock is dependent upon, among other things, the employees’ and directors’ continued service with the Company.
The following is a summary of activity for the three months ended March 31, 2023:
| Restricted Stock | Weighted Average Grant Date Fair Value | |||||||
| (in thousands) | ||||||||
| Non-vested shares outstanding at January 1, 2023 | $ | |||||||
| Awards granted | ||||||||
| Awards vested | ( | ) | ||||||
| Awards forfeited | ||||||||
| Non-vested shares outstanding at March 31, 2023 | $ | |||||||
During the three months ended March 31, 2023,
In connection with the Arrangement with TransGlobe and pursuant to the Arrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of cash or TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be
RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the Arrangement. Each RSU vests annually over a -year period. On December 16, 2022, Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of RSU activity for the three months ended March 31, 2023:
| Restricted Stock | Weighted Average Conversion Date Fair Value | |||||||
| (in thousands) | ||||||||
| Non-vested shares outstanding at January 1, 2023 | $ | |||||||
| Awards granted | — | — | ||||||
| Awards vested | ( | ) | ||||||
| Awards forfeited | ( | ) | ||||||
| Non-vested shares outstanding at March 31, 2023 | $ | |
| |||||
During the three months ended March 31, 2023,
PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021; and 64.4% for PSUs granted in 2022. All PSUs granted vest on the anniversary of their grant date. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of PSU activity for the three months ended March 31, 2023:
| Restricted Stock | Weighted Average Conversion Date Fair Value | |||||||
| (in thousands) | ||||||||
| Non-vested shares outstanding at January 1, 2023 | $ | |||||||
| Awards granted | — | — | ||||||
| Awards vested | ( | ) | ||||||
| Awards forfeited | ( | ) | ||||||
| Non-vested shares outstanding at March 31, 2023 | $ | |||||||
During the three months ended March 31, 2023,
DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's Board of Directors. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. At March 31, 2023, approximately
Stock appreciation rights (“SARs”)
SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s board of directors.
During the three months ended March 31, 2023, the Company did grant SARs to employees or directors.
SAR activity for the three months ended March 31, 2023 is provided below:
| Number of Shares Underlying SARs | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||||||
| (in thousands) | (in years) | (in thousands) | ||||||||||||||
| Outstanding at January 1, 2023 | $ | |||||||||||||||
| Granted | ||||||||||||||||
| Exercised | ( | ) | ||||||||||||||
| Unvested SARs forfeited | ||||||||||||||||
| Vested SARs expired | ||||||||||||||||
| Outstanding at March 31, 2023 | $ | $ | ||||||||||||||
| Exercisable at March 31, 2023 | $ | $ | ||||||||||||||
Other Benefit Plans
The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive
16. INCOME TAXES
VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions that include Canada, Egypt, Equatorial Guinea and Gabon.
Income taxes attributable to continuing operations for the three months ended March 31, 2023 and 2022 are attributable to foreign taxes payable in Gabon and Egypt, as well as income taxes in the U.S.
Provision for income taxes related to income from continuing operations consists of the following:
| Three Months Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| U.S. Federal: | (in thousands) | |||||||
| Current | $ | $ | ||||||
| Deferred | ( | ) | ||||||
| Foreign: | ||||||||
| Current | ||||||||
| Deferred | ||||||||
| Total | $ | $ | ( | ) | ||||
The Company’s effective tax rate for the three months ended March 31, 2023 and 2022, excluding the impact of discrete items, was
As of March 31, 2023, the Company had
17. OTHER COMPREHENSIVE INCOME
The Company’s other comprehensive loss was $
The components of accumulated other comprehensive income are as follows:
| Currency Translation Adjustments | ||||
| (in thousands) | ||||
| Balance at December 31, 2022 | $ | |||
| Accumulated other comprehensive income (loss) before reclassifications | ( | ) | ||
| Balance at March 31, 2023 | $ | |||
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:
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volatility of, and declines and weaknesses in crude oil, natural gas and NGLs prices, as well as our ability to offset volatility in prices through the use of hedging transactions; |
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our ability to remediate our material weaknesses; |
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the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves; |
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impairments in the value of our crude oil, natural gas and NGLs assets; |
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future capital requirements; |
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our ability to maintain sufficient liquidity in order to fully implement our business plan; |
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our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements; |
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the ability of the BWE Consortium to successfully execute its business plan; |
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our ability to attract capital or obtain debt financing arrangements; |
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our ability to pay the expenditures required in order to develop certain of our properties; |
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operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs; |
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difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs; |
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the impact of competition; |
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our ability to identify and complete complementary opportunistic acquisitions; |
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our ability to effectively integrate assets and properties that we acquire into our operations; |
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weather conditions; |
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the uncertainty of estimates of crude oil, natural gas and NGLs reserves; |
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currency exchange rates and regulations; |
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unanticipated issues and liabilities arising from non-compliance with environmental regulations; |
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the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon; |
| ● | the ultimate resolution of our negotiations with the Egyptian General Petroleum Corporation ("EGPC") relating to the Effective Date Adjustment (as defined below); | |
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the availability and cost of seismic, drilling and other equipment; |
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difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets; |
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timing and amount of future production of crude oil, natural gas and NGLs; |
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hedging decisions, including whether or not to enter into derivative financial instruments; |
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general economic conditions, including any future economic downturn, the impact of inflation, and disruption in financial credit; |
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our ability to enter into new customer contracts; |
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changes in customer demand and producers’ supply; |
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actions by the governments of and events occurring in the countries in which we operate; |
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actions by our joint venture owners; |
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compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change; |
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the outcome of any governmental audit; and |
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actions of operators of our crude oil, natural gas and NGLs properties. |
The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the 2022 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.
Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this “Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.
INTRODUCTION
VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs. As operator, we have production operations and conduct exploration activities in Gabon, West Africa, Egypt and Canada. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 to the Financial Statements, we have discontinued operations associated with our activities in Angola, West Africa and Yemen.
RECENT DEVELOPMENTS
Dividend Policy
On February 14, 2023, our board of directors increased our quarterly cash dividend policy to an expected $0.0625 per common share per quarter, commencing in the first quarter of 2023 and concurrently declared a quarterly cash dividend of $0.0625 per common share that was paid on March 31, 2023 to stockholders of record at the close of business on March 24, 2023. On May 9, 2023 our board announced a cash dividend of $0.0625 per share of common stock to be paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Share Buyback Program
On November 1, 2022, VAALCO announced that its board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the 10b5-1 Plan to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using cash on hand and cash flow from operations.
The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, VAALCO's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, our third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, has authority to purchase VAALCO common stock in accordance with the terms of the Plan.
TransGlobe Merger
On October 13, 2022, VAALCO and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares pursuant to the Arrangement and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement.
Additionally, prior to the effective time of the Arrangement, TransGlobe repaid outstanding obligations and liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million. On December 19, 2022, TransGlobe, as an indirect wholly-owned subsidiary of VAALCO, voluntarily delivered a notice of termination to ATB Financial relating to the ATB Facility. As of December 31, 2022, no amounts were drawn on the revolving loan facility. On January 5, 2023, the ATB Facility was formally closed.
The actual impact of the Arrangement Agreement was an increase to “Crude oil, natural gas and NGLs sales” of $43.7 million and $9.7 million of “Net income” in the condensed consolidated statements of operations and comprehensive income for the three months ended March 31, 2023.
Entry into a Facility Agreement
On May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”), a wholly owned subsidiary of VAALCO, entered into a facility agreement (the “Facility Agreement”) by and among VAALCO, VAALCO Gabon, SA (“VAALCO Gabon” and, together with VAALCO, the “Guarantors”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an aggregate maximum principal amount of up to $50.0 million. Subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million. See “Capital Resources and Liquidity – RBL Facility Agreement” for more information regarding the Facility.
Recent Operational Updates
Gabon
VAALCO completed its 2021/2022 drilling campaign in the fourth quarter of 2022. We are currently evaluating locations and planning for the next drilling campaign at Etame that is expected to occur in 2024. In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) and related field reconfiguration processes. This project provides a low cost FSO solution that increases the storage capacity for the Etame block. The Company will continue to focus on operational excellence, including production uptime and enhancement in 2023 to minimize decline until the next drilling campaign.
The cost of the 2021/2022 drilling program with four wells and two workovers was $180 million, or $114 million, net to VAALCO’s participating interest.
For the three months ended March 31, 2023, all wells were online from the end of 2022 as the gas lift compression system was successfully commissioned. This gas lift compression system increased the production and the reliability of two subsea wells positively, impacting our volumes for the three months ended March 31, 2023.
The focus during the first quarter of 2023 was continued production optimization of the new flow line configurations at the Etame Facility, as all production transits through the Etame platform for final processing before being pumped to the FSO. Since the field reconfiguration in 2022, a better understanding of the field’s operating parameters has resulted in a more efficient and cost effective flow assurance program. Combining this with chemical injection optimization and pipeline pigging adjustments both on frequency of pigging and flow path targeting has increased production and provided more stable operations resulting in lower downtime.
Preventative maintenance activities returned to levels prior to the field reconfiguration, as the focus came back to steady state operation following project completion.
Egypt
We continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed the Arta 77Hz horizontal well drilling at the beginning of 2023 and released the rig on January 11, 2023. The well is flowing at approximately 200 bopd with minimal water. We expect cleanup on this well to continue for an extended period of time. This delayed the 2023 drilling campaign. However, during the remainder of the quarter, we drilled and cased five development wells, (East Arta 53 ("EA-53"), K-81, K-79, Arta-80 Red Bed, and Arta 81 Red Bed).
The EA-53 development well was drilled to a total depth of 1,279 meters targeting Red Bed reservoirs in the East Arta Field. The well was fully logged and evaluated. The Red Bed reservoir has an estimated 4.5 meters of net oil pay. The lower most Red Bed reservoir was perforated in the EA-53 well and is producing 100% water which was unexpected given that the East Arta 21 well's current production is at a 67% water cut and the East Arta 39 well's production is at an 80% water cut. There is a plan to fracture stimulate the EA-53 well to try and get oil production.
The K-79 well was drilled as a vertical development well with the ASL-D reservoir as the primary target, and the ASL-B and ASL-E reservoirs as secondary targets. The well spudded on February 21, 2023, and reached TD on March 1, 2023 at a depth of 1,739 m in the ASL-F reservoir. Log analysis indicates the presence of 57.9m net pay, 9m in the ASL-D reservoir, 31 m in the ASL-B reservoir and 13.7m in the ASL-A sands. The well perforated in the ASL-B1 and B2 zones from 1,273 to 1,285m and 1,302 to 1,308m. Initial production commenced on March 15, 2023 at 192 bopd.
The Arta-80 development well reached its primary objective of the Red Bed reservoir approximately 24.4 meters higher than prognosis and encountered a total of 10 meters of net pay. The well spudded on March 10, 2023 and reached TD on March 15, 2023 at a depth of 1,250 meters in the Thebes Formation. Open hole log evaluation indicated the presence of 10.5 meters of net pay in the Red Bed primary reservoir. The top 9.5 meters of the Red Beds were perforated from 1,105 to 1,115 meters and began to produce on March 25, 2023 with initial production of 403 bopd.
The Arta-81 development well spud on March 21, 2023 and reached TD on March 25, 2023 at a depth of 1,264 meters within the Thebes formation. It achieved the primary objective 4.2 meters higher than prognosis and encountered a total of 9 meters of net pay in the Red Beds reservoir. The well was perforated in the top 7.9 meters of the Red Bed reservoir (1,133-1,423 meters) and began to produce on April 6, 2023 with an initial production of 317 bopd.
The HE-4 appraisal well was drilled to a total depth of 1,850m in the Bakr sand formation, reaching its primary objective of penetrating oil-bearing sands in the ASL-B formation. The well spudded on April 2, 2023 and reached TD on April 9, 2023. Open hole log evaluation indicated 8.5 meters of net pay across 3 sand zones in the ASL-B including a new sand formation not seen in offset wells to the north. The well was perforated from 1,590-1,594 meters in the lowermost sand and was put on production on April 19, 2023. Current production is approximately 180 bopd (field estimate) at 50% water cut.
The HE-5INJ injection well is planned downdip of HE-1X, HE-2 and the proposed HE-3 well (to be drilled after HE-5INJ). The reservoirs in this pool are relatively thin and pressure data indicates depletion. Injecting into the reservoir will support pressure and should improve the estimated ultimate recovery of the producing ASL-B zones.
The SGZ-6X well in the South Ghazalat concession in the Western Desert remains shut-in. Recomplete work on the well is underway to put it back on production to retain the acreage. Intervention planning was completed during the first quarter of 2023 and operations have now started in order to resume production from the Western Desert.
Canada
Early in 2023, two wells, the 1Q100/04-10-29-03W5 and the 4-19-29-3W5, were tied in. Initially, the tie-in had been scheduled for late 2022 but due to weather and contractor delays, these were moved into 2023 (1Q100/04-10-29-03W5 /4-19-29-3W5). Both wells are now online and producing.
The 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5, spud on January 28, 2023. The well was drilled to a total depth of 6,713 meters. The second well of the program, 16-30-29-3W5, was spud on February 22, 2023, and drilled to total depth of 4,403 meters. The 2 wells were completed between late March and early April with good oil shows. Both wells are currently being equipped for production and are expected online in May 2023 with a significant reduction in historical cycle times compared to previous wells.
ACTIVITIES BY ASSET
Gabon
Offshore – Etame Marin Block
Development and Production
We operate the Etame Marin Block on behalf of a consortium of companies. As of March 31, 2023, production operations in the Etame Marin block included fifteen platform wells, plus two subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery and processing at the Etame platform. From the Etame platform, the crude oil is pumped through a riser system to the FSO where it is stored and ultimately offloaded. The leased FSO is anchored to the seabed on the block. The Etame field currently has a combined total of seventeen producing wells. During the three months ended March 31, 2023 and 2022, production from the block was 1,603 MBbls (820 MBbls, net) and 1,416 MBbls (725 MBbls, net), respectively, as discussed below in “Results of Operations”.
Egypt
In Egypt, as of March 31, 2023, our interests are spread across two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions, and the Western Desert, which contains the South Ghazalat concession. Both of our Egyptian blocks are PSCs among the Egyptian General Petroleum Corporation (“EGPC”), the Egyptian government and us. We are the operator and have a 100% working interest in both PSCs. During the three months ended March 31, 2023, production from the Eastern Desert was 903 MBbls (616 MBbls, net) as discussed below in “Results of Operations”.
The SGZ-6X well in the South Ghazalat concession in the Western Desert remains shut-in.
Canada
In Harmattan, Canada, we own production and working interests in the Cardium light oil and Mannville liquids-rich gas assets. This property produces oil and associated natural gas from the Cardium and Viking zones and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to 2,600 meters. All gas is delivered to a third party non-operated gas plant for processing. During the three months ended March 31, 2023, production from our Canadian assets was 239 MBoe to our working interest (211 MBoe, net) as discussed below in “Results of Operations”.
Equatorial Guinea
As of March 31, 2023, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. In February of 2023, we acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.8 million at first commercial production of the Block. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus development plan has been initiated. VAALCO as operator, is in the process of working through the project charter and timing of key milestones. In addition, there are some minor changes required by the Joint Operating Agreement that require final ratification by the joint venture.
The Block P production sharing contract ("PSC") provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development. The PSC also includes the portions of Block P not associated with the Block P - Venus development.
DISCONTINUED OPERATIONS - ANGOLA AND YEMEN
In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the Financial Statements for all periods presented. See Note 3 to the Financial Statements. For the three months ended March 31, 2023 and 2022, the Angola segment did not have a material impact on our financial position, results of operations, cash flows and related disclosures.
As part of the Arrangement with TransGlobe, we acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S-1. In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S-1. The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in our consolidated statements of operations and comprehensive income. Our segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in our consolidated statements of cash flows. For the three months ended March 31, 2023, the Yemen segment did not have a material impact on our financial position, results of operations, cash flows and related disclosures.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flows
Our cash flows for the three months ended March 31, 2023 and 2022 are as follows:
| Three Months Ended March 31, |
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| 2023 |
2022 |
Increase (Decrease) in 2023 over 2022 |
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| (in thousands) |
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| Net cash provided by operating activities before changes in operating assets and liabilities |
$ | 32,803 | $ | 27,859 | $ | 4,944 | ||||||
| Net change in operating assets and liabilities |
9,216 | (28,599 | ) | 37,815 | ||||||||
| Net cash provided by (used in) continuing operating activities |
42,019 | (740 | ) | 42,759 | ||||||||
| Net cash used in discontinued operating activities |
(13 | ) | (18 | ) | 5 | |||||||
| Net cash provided by (used in) operating activities |
42,006 | (758 | ) | 42,764 | ||||||||
| Net cash used in investing activities |
(27,700 | ) | (23,148 | ) | (4,552 | ) | ||||||
| Net cash used in financing activities |
(13,539 | ) | (2,118 | ) | (11,421 | ) | ||||||
| Effects of exchange rate changes on cash |
(309 | ) | — | (309 | ) | |||||||
| Net change in cash, cash equivalents and restricted cash |
$ | 458 | $ | (26,024 | ) | $ | 26,482 | |||||
The $4.9 million increase in net cash provided by operating activities before changes in operating assets and liabilities was due to lower cash settlements on derivative contracts partially offset by lower net income due to higher production costs and higher current income taxes The net increase in changes provided by operating assets and liabilities of $37.8 million for the three months ended March 31, 2023 compared to the same period of 2022 was primarily related to positive changes in receivables accounts with joint venture owners and other assets along with positive changes in accounts payable and foreign income taxes (collectively $79.1 million). Partially offsetting these changes were negative changes in other receivables, crude oil inventory, deferred taxes and accrued liabilities and other (collectively ($41.3) million).
The $4.6 million increase in net cash used in investing activities during the three months ended March 31, 2023 was due to increases in capital spending to costs associated with the development drilling programs in Egypt and Canada. For the three months ended March 31, 2022, cash used in investing activities was mainly for the Etame-8H development well and Etame field reconfiguration and other items to support the 2021/2022 drilling campaign.
Net cash used in financing activities during the three months ended March 31, 2023 included $6.7 million for dividend distributions, $5.4 million for treasury stock repurchases made under our stock repurchase plan as discussed in Note 10 to our unaudited condensed consolidated financial statements or as a result of tax withholding on options exercised and on vested restricted stock as discussed in Note 15 to our unaudited condensed consolidated financial statements, and $1.7 million of principal payments on our finance leases partially offset by $0.3 million in proceeds from options exercised. For the three months ended March 31, 2022, cash used in financing activities was mainly due to dividend distributions of $1.9 million, cash used in the purchase of treasury shares as a result of tax withholding on options exercised of $0.4 million partially offset by proceeds received from options exercised of $0.2 million.
Capital Expenditures
For the three months ended March 31, 2023 we had accrual basis capital expenditures attributable to continuing operations of $25.4 million compared to $31.8 million accrual basis capital expenditures for the same period in 2022. For the three months ended March 31, 2023, our cash spending related to the payments for the 2023 drilling campaigns in Egypt and Canada. During the same period in 2022, our spending was concentrated on the 2021/2022 drilling campaign, Etame field reconfigurations and FSO projects.
See discussion below in “Capital Resources, Liquidity and Cash Requirements” for further information.
Regulatory and Joint Interest Audits
We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 10 to the Financial Statements for further discussion.
Commodity Price Hedging
The price we receive for our crude oil, natural gas and NGLs significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Crude oil and natural gas commodities and, therefore their prices can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future.
Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps and costless collars to hedge price risk associated with a portion of our anticipated crude oil production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the unaudited condensed consolidated statements of operations and comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheet.
See the table below for the unexpired contracts at March 31, 2023:
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||||||||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||||||||
| April 2023 - June 2023 |
Collars |
Dated Brent |
95,500 | $ | 65.00 | $ | 100.00 | |||||||
Pursuant to the Facility entered into in May 2022, we are required to hedge a portion of our anticipated oil production at the time we draw down on the Facility.
Subsequent Event
On April 4, 2023, we entered into additional derivatives contracts for the third quarter of 2023. The details are in the chart below:
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||||||||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||||||||
| July 2023 - September 2023 |
Collars |
Dated Brent |
95,000 | $ | 65.00 | $ | 96.00 | |||||||
Cash on Hand
At March 31, 2023, we had unrestricted cash of $52.1 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.
We currently sell all our crude oil production from Gabon under a crude oil sales and marketing agreement ("COSMA") with Glencore. Under the COSMA all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the Final Maturity Date of the Facility, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Revenues associated with the sales of our crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, we record the EGPC’s share of production as royalties which are netted against revenue. With respect to taxes in Egypt, our income taxes under the terms of the Merged Concession Agreement are the liability of TransGlobe Petroleum International ("TGPI"), a wholly-owned indirect subsidiary of VAALCO. TGPI's income taxes are paid by EGPC on behalf of TGPI out of EGPC’s production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of TGPI are recognized as oil and gas sales revenue and income tax expense for reporting purposes.
For the three months ended March 31, 2023, all sales in Egypt were to Mercuria. Sales to Mercuria are normally settled within 30 days.
Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are recognized net of royalties and transportation costs. Revenues are measured at the fair value of the consideration received.
Settlement of accounts receivable in Canada occur on the 25th of the following month after production.
Capital Resources, Liquidity and Cash Requirements
Historically, our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. For example, we recently took actions to improve our liquidity position by entering into the Facility Agreement. We believe that the recent Facility significantly improves our financial flexibility and our ability to achieve accretive growth by providing access to cash if required for potential future development programs or to fund inorganic acquisition opportunities. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations, including the addition of our Egypt and Canada segments, to support our current cash requirements, including the FSO charter, drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures, repurchases of shares or pay dividends or other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.
Merged Concession Agreement
On January 19, 2022, legacy subsidiaries of TransGlobe executed the Merged Concession Agreement with EGPC to update and merge TransGlobe’s three Egyptian concessions in West Bakr, West Gharib and NW Gharib (the “Merged Concession”). The modernization payments under the Merged Concession Agreement total $65.0 million and are payable over six years from the Merged Concession Effective Date. Under the Merged Concession Agreement, we will be required to pay an additional $10.0 million on February 1 for each of the next three years. In addition, we have committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (totaling $150.0 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which is subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.
RBL Facility Agreement and Available Credit
On May 16, 2022, VAALCO Gabon (Etame), Inc. entered into Facility Agreement by and among VAALCO, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C. and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million. Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.
The Facility provides for determination of the borrowing base asset based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.
The Borrower’s obligations under the Facility Agreement are guaranteed by Guarantors and secured by interests, rights, activities, assets, entitlements, and development in the Etame Marin Permit (Block G64-160) Field and any other assets which are approved by the Majority Lenders (as defined in the Facility Agreement).
Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).
Pursuant to the Facility Agreement, we shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.
The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of September 30, 2022, our borrowing base was $50.0 million. The amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. We were in compliance with all debt covenants at March 31, 2022. As of March 31, 2022, we had no outstanding borrowings under the facility.
The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).
Cash Requirements
Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the TransGlobe acquisition transaction costs, dividend payments, funding of our share buyback program, merged concession agreement, future lease payments and abandonment funding, each of which is discussed in further detail below.
Abandonment Funding – Under the terms of the Etame PSC, we have 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, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, a new abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis. The new abandonment estimate has been presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. At March 31, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the 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.
Leases – We are a party to several operating and financing lease arrangements, including operating leases for the corporate office, a drilling rig, rental of marine vessels and helicopters, warehouse and storage facilities, equipment and financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The annual costs of these leases are significant to us. For further information see Note 12 to our consolidated financial statements.
Merged Concession Agreement – On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession, we agreed to substitute the February 1, 2023 payment and issue a $10.0 million credit against receivables owed from EGPC. We will make three further annual equalization payments of $10.0 million each beginning February 1, 2024, until February 1, 2026. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date"). As of March 31, 2023, the $50 million of financial work commitments had been delivered to EGPC.
FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement with World Carrier to replace the existing FPSO with a FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the TELI vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions. Pursuant to the Operating Agreement, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO. As consideration for the performance by World Carrier of the Operator Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Operating Agreement) until the end of the term, with such term being the same as the term in the Bareboat Charter.
On October 19, 2022, we issued final acceptance certificate of the FSO. On December 4, 2022, the first lifting from the FSO was successfully completed at the same time the final remaining volumes from the FPSO were removed.
BWE Consortium – On October 11, 2021, we announced our entry into a consortium with BW Energy and Panoro Energy and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of the PSC with the Gabonese government. BW Energy will be the operator with a 37.5% working interest. We will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by an additional two years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.
Drilling Programs – In Egypt, we continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed the Arta 77Hz horizontal well drilling at the beginning of 2023 and released the rig on January 11, 2023. The well is flowing at approximately 200 bopd with minimal water. We expect cleanup on this well to continue for an extended period of time. This delayed the 2023 drilling campaign. However, during the remainder of the quarter, we drilled and cased five development wells, (East Arta 53 ("EA-53"), K-81, K-79, Arta-80 Red Bed, and Arta 81 Red Bed).
The EA-53 development well was drilled to a total depth of 1,279 meters targeting Red Bed reservoirs in the East Arta Field. The well was fully logged and evaluated. The Red Bed reservoir has an estimated 4.5 meters of net oil pay. The lower most Red Bed reservoir was perforated in the EA-53 well and is producing 100% water which was unexpected given that the East Arta 21 well's current production is at a 67% water cut and the East Arta 39 well's production is at an 80% water cut. There is a plan to fracture stimulate the EA-53 well to try and get oil production.
The K-79 well was drilled as a vertical development well with the ASL-D reservoir as the primary target, and the ASL-B and ASL-E reservoirs as secondary targets. The well spudded on February 21, 2023, and reached TD on March 1, 2023 at a depth of 1,739 meters in the ASL-F reservoir. Log analysis indicates the presence of 57.9m net pay, 9m in the ASL-D reservoir, 31 m in the ASL-B reservoir and 13.7m in the ASL-A sands. The well perforated in the ASL-B1 and B2 zones from 1,273 to 1,285m and 1,302 to 1,308m. Initial production commenced on March 15, 2023 at 192 bopd.
The Arta-80 development well reached its primary objective of the Red Bed reservoir approximately 24.4 meters higher than prognosis and encountered a total of 10 meters of net pay. The well spudded on March 10, 2023 and reached TD on March 15, 2023 at a depth of 1,250 meters in the Thebes Formation. Open hole log evaluation indicated the presence of 10.5 meters of net pay in the Red Bed primary reservoir. The top 9.5 meters of the Red Beds were perforated from 1,105 to 1,115 meters and began to produce on March 25, 2023 with initial production of 403 bopd.
The Arta-81 development well spud on March 21, 2023 and reached TD on March 25, 2023 at a depth of 1,264 meters within the Thebes formation. It achieved the primary objective 4.2 meters higher than prognosis and encountered a total of 9 meters of net pay in the Red Beds reservoir. The well was perforated in the top 7.9 meters of the Red Bed reservoir (1,133-1,423 meters) and began to produce on April 6, 2023 with an initial production of 317 bopd.
The HE-4 appraisal well was drilled to a total depth of 1,850m in the Bakr sand formation, reaching its primary objective of penetrating oil-bearing sands in the ASL-B formation. The well spudded on April 2, 2023 and reached TD on April 9, 2023. Open hole log evaluation indicated 8.5 meters of net pay across 3 sand zones in the ASL-B including a new sand formation not seen in offset wells to the north. The well was perforated from 1,590-1,594 meters in the lowermost sand and was put on production on April 19, 2023. Current production is approximately 180 bopd (field estimate) at 50% water cut.
The HE-5INJ injection well is planned downdip of HE-1X, HE-2 and the proposed HE-3 well (to be drilled after HE-5INJ). The reservoirs in this pool are relatively thin and pressure data indicates depletion. Injecting into the reservoir will support pressure and should improve the estimated ultimate recovery of the producing ASL-B zones.
In Canada, the 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5 which was spud on January 28, 2023. The well was drilled to a total depth of 6,713 meters. The second well of the program, 16-30-29-3W5, was spud on February 22, 2023, and drilled to total depth of 4,403 meters. The 2 wells were completed in late March and early April and are currently being equipped for production.
TransGlobe Acquistion – On October 13, 2022, VAALCO and AcquireCo completed the business combination with TransGlobe. At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to receive 0.6727 of a share of VAALCO common stock. The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. In addition, we incurred $14.6 million of transaction costs associated with the acquisition agreement.
Dividend Policy – On February 14, 2023, we announced that our board of directors adopted of a quarterly cash dividend of an expected $0.0625 per common share per quarter, commencing in the first quarter of 2023 and also declared a quarterly cash dividend of $0.0625 per common share, which was paid on March 31, 2023 to stockholders of record at the close of business on March 24, 2023. On May 9, 2023, our board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Share Buyback Program – On November 1, 2022, we announced that our board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the 10b5-1 Plan to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using our cash on hand and cash flow from operations. As of March 31, 2023, approximately $22.5 million remained available for repurchase under current authorizations.
Trends and Uncertainties
Geopolitical Climate and Other Market Forces – Increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain, which in turn have had, and may continue to have, an impact on our business. Management believes the ongoing war between Russia and Ukraine and its related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. For example, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities has lengthened, leading to delays and, in most cases, prices for materials have increased.
The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The ongoing conflict has caused, and could intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.
Further, the slowdown in the Chinese economy is negatively impacting the global market and the global supply chain problems may have a material adverse impact on our financial results and business operations, including our timing and ability to complete future drilling campaigns and other efforts required to advance the development of our crude oil, natural gas and NGLs properties.
Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+. On October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. In April 2023, OPEC+ reaffirmed its decision to reduce overall oil production by 2 MMBbls per day from November 2022 through December 2023. Additionally, certain member countries announced additional voluntary reductions totaling 1.2 MMBbls through December 2023, which is in addition to the 500 MBbls per day voluntary reduction announced by Russia in February 2023. Included in the 1.2 MMBbls per day reduction was a voluntary reduction by the Gabonese government of 8 MBbls per day, which will go into effect in May 2023 and is expected to extend through the remainder of 2023. To date, we have not received any mandate to reduce our current oil production from the Etame Marin block as a result of the OPEC+ initiative. Brent crude prices were approximately $79.19 per barrel as of March 31, 2023.
ESG and Climate Change Effects – ESG matters continue to attract considerable public and scientific attention. In particular, we expect continued regulatory attention on climate change issues and emissions of greenhouse gases (“GHG”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion). This increased attention to climate change and environmental conservation may result in demand shifts away from crude oil and natural gas products to alternative forms of energy, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG standards, including the reduction of our carbon footprint and measurement of GHG emissions. ESG is important to us, and we are in the process of developing a multi-year plan to establish and document our ESG base currently and developing a systematic plan to monitor and improve matters related to ESG and climate change going forward.
COVID-19 Pandemic – While crude oil, natural gas and NGLs prices are currently stable, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude oil, natural gas and NGLs prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon, Egypt or Canada may have on our ability to continue to conduct our operations.
Hedging
We seek to mitigate the impact of volatility in crude oil prices through hedging. See the table below for the unexpired contracts entered into prior to March 31, 2023:
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||||||||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||||||||
| April 2023 - June 2023 |
Collars |
Dated Brent |
95,500 | $ | 65.00 | $ | 100.00 | |||||||
Pursuant to the Facility entered into in May 2022, we are required to hedge a portion of our anticipated oil production at the time that we draw down on the Facility.
Subsequent Event
On April 3, 2023, we entered into additional derivatives contracts for the third quarter of 2023. The details are in the chart below:
| Settlement Period |
Type of Contract |
Index |
Average Monthly Volumes |
Weighted Average Put Price |
Weighted Average Call Price |
|||||||||
| (Bbls) |
(per Bbl) |
(per Bbl) |
||||||||||||
| July 2023 - September 2023 |
Collars |
Dated Brent |
95,000 | $ | 65.00 | $ | 96.00 | |||||||
CRITICAL ACCOUNTING POLICIES
There have been no material changes to our critical accounting policies subsequent to December 31, 2022.
NEW ACCOUNTING STANDARDS
See Note 2 to the condensed consolidated financial statements.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2023 Compared to the Three Months Ended March 31, 2022
Net income for the three months ended March 31, 2023 was $3.5 million compared to net income of $12.2 million for the same period of 2022. See discussion below for changes in revenue and expense.
Crude oil and natural gas revenues increased $11.7 million, or approximately 17%, to $80.4 million during the three months ended March 31, 2023 from $68.7 million for the same period in the prior year. The revenue increase is attributable to higher volumes sold in Gabon and the addition of the Egypt and Canada segments acquired in the Arrangement with TransGlobe, partially offset by lower realized sales prices.
| Three Months Ended March 31, |
||||||||||||
| 2023 |
2022 |
Increase/(Decrease) |
||||||||||
| (in thousands except per Boe information) |
||||||||||||
| Net crude oil, natural gas, and NGLs sales volume (MBoe) |
1,224 | 616 | 608 | |||||||||
| Average crude oil, natural gas and NGLs sales price (per Boe) |
$ | 65.68 | $ | 109.65 | $ | (43.97 | ) | |||||
| Net crude oil, natural gas, and NGLs revenue |
$ | 80,403 | $ | 68,656 | $ | 11,747 | ||||||
| Operating costs and expenses: |
||||||||||||
| Production expense |
28,200 | 18,360 | 9,840 | |||||||||
| Exploration expense |
8 | 127 | (119 | ) | ||||||||
| Depreciation, depletion and amortization |
24,417 | 4,673 | 19,744 | |||||||||
| General and administrative expense |
5,224 | 4,994 | 230 | |||||||||
| Credit losses and other |
935 | 492 | 443 | |||||||||
| Total operating costs and expenses |
58,784 | 28,646 | 30,138 | |||||||||
| Other operating expense, net |
— | (5 | ) | 5 | ||||||||
| Operating income |
$ | 21,619 | $ | 40,005 | $ | (18,386 | ) | |||||
The revenue changes in the three months ended March 31, 2023 compared to the same period in 2022 identified as related to changes in price or volume, are shown in the table below:
| (in thousands) |
||||
| Price |
$ | (53,832 | ) | |
| Volume |
66,690 | |||
| Other |
(1,111 | ) | ||
| $ | 11,747 |
| (1) |
The price in the table above excludes revenues attributed to carried interests |
The table below shows net production, sales volumes and realized prices for both periods.
| Three Months Ended March 31, |
||||||||
| 2023 |
2022 |
|||||||
| Net crude oil, natural gas and NGLs production (MBoe) |
1,647 | 725 | ||||||
| Net crude oil, natural gas and NGLs sales (MBoe) |
1,224 | 616 | ||||||
| Average realized crude oil, natural gas and NGLs price ($/Boe) |
$ | 65.68 | $ | 109.65 | ||||
| Average Dated Brent spot price* ($/Bbl) |
$ | 81.07 | $ | 100.87 | ||||
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Crude oil, natural gas and NGL revenues increased $11.7 million, or approximately 17.0%, during the three months ended March 31, 2023 compared to the same period of 2022.
Gabon
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $36.7 million of revenue to the Company’s total revenue during the three months ended March 31, 2023. This compares to the $68.7 million of revenue contributed by the Segment during the three months ended March 31 ,2022. The total barrels lifted in Gabon for the three months ended March 31 was less than the barrels lifted during the same period in 2022, mainly due to the timing of liftings. In addition, the Gabon per barrel price received during the three months ended March 31, 2023 was $30.00 less than the price received in 2022. Our share of crude oil inventory, excluding royalty barrels, was approximately 408,543 and 174,250 barrels at March 31, 2023 and 2022, respectively.
Egypt
Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the three months ended March 31, 2023, all the oil sold in Egypt was through third party cargo sales. The Company’s Egypt segment contributed $34.8 million of revenue to the Company’s total revenue for the quarter. At the end of the quarter, the Company’s Egypt segment had approximately 63,000 barrels at March 31, 2023 in oil inventory. Since the Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended March 31 ,2022.
Canada
Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $8.9 million of revenue to the Company’s total revenue for the quarter. Since the Company acquired its Canadian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended March 31 ,2022
Production expenses increased $9.8 million, or approximately 54%, for the three months ended March 31, 2023 to $28.2 million from $18.4 million for the same period in the prior year. The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher costs associated with boats, diesel and operating costs. VAALCO has seen inflationary pressure on personnel and contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended March 31, 2023 decreased to $23.91 per barrel from $29.83 per barrel for the three months ended March 31, 2022 primarily as a result of higher sales volumes. For both the three months ended March 31, 2023 and 2022, respectively, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic. For the three months ended March 31, 2023 the costs associated with proactive measures related to COVID were not material. For the three months ended March 31, 2022 , we incurred $0.9 million in higher costs related to the proactive measures taken in response to the pandemic.
Exploration expense for the three months ended March 31, 2023 and for the three months ended March 31, 2022 was not material to our results.
Depreciation, depletion and amortization costs increased $19.7 million, or approximately 423% for the three months ended March 31, 2023 to $24.4 million from $4.7 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense for the three months ended March 31, 2023 compared to thee months ended march 31 2022, is due to higher depletable costs associated with the FSO, the field reconfiguration capital costs at Etame and the step-up to fair value of the TransGlobe assets.
General and administrative expenses increased $0.2 million, or 5% for the three months ended March 31, 2023 to $5.2 million from$5.0 million for the same period in the prior year. The increase in general and administrative expenses is primarily due to higher professional fees for the three months ended March 31, 2023 compared to the same period in 2022.
Credit losses and other increased by $0.4 to $0.9 million for the three months ended March 31, 2023 from $0.5 million for the three months ended March 31, 2022. We adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”) on January 1, 2023. In connection with the adoption of ASU 2016-13, we established an opening balance sheet adjustment related to a receivable from a state sponsored oil refinery where we delivered oil pursuant to the domestic market needs obligation under the Etame PSC. During the three months ended March 31, 2023, we recognized an additional amount to the credit loss allowance of $0.4 million for crude oil delivered to the refinery during the quarter. For the three months ended March 31, 2022, no allowance was established related to this receivable as the state sponsored oil refinery made timely payments of the amounts owed to the Company.
Historically, we reported amounts currently considered as credit loss expense and other as bad debt expense and, prior to the adoption of ASU 2016-13, bad debt expense mainly related to the our VAT balances under the Etame PSC. When we are invoiced by a vendor an amount is added for VAT (a cost plus VAT amount) and we pay the vendor invoice. Since we are an oil and gas company, we are exempt from VAT and therefore request reimbursement from the State of Gabon for VAT for amounts we’ve paid. Due to the late reimbursement nature of the VAT receivable by the State of Gabon, the Company established an allowance against the receivable The allowance related to the VAT receivable was $8.4 million on December 31, 2022. For the three months ended March 31, 2023 we added $0.5 million to the allowance account for the current’s quarters activity. We are now reporting under the condensed consolidated income statement line item “Credit losses and other” the activity related to financial assets under ASC 2016-13 and activity regarding other allowance accounts. For more information on credit losses and other allowances, see Note 1 to the unaudited condensed consolidated financial statements.
Other operating expense, net for each of the three months ended March 31, 2023 and 2022 was not material to our results.
Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Note 8 to the unaudited condensed consolidated financial statements. Derivative loss decreased by $31.8 million, or approximately 100% to an immaterial loss for the three months ended March 31, 2023 from a loss of $31.8 million during the same period in the prior year. Derivative gains (losses) for the three months ended March 31, 2022 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the three months ended March 31, 2022. During 2022, we changed the type of our derivative instruments from swaps to costless collars. Our derivative instruments currently cover a portion of our production through September 2023.
Interest expense, net was $2.2 million for the three months ended March 31, 2023 compared to an expense of $0.0 million during the same period in 2022. The increase of net interest expense for the three months ended March 31, 2023, primarily results from our finance lease relating to the FSO but also includes commitments fees incurred on the Facility, amortization of debt issue costs related to the Facility and interest associated with our other finance leases partially offset by interest income.
Other (expense) income changed by $0.4 million to expense of $1.1 million for the three months ended March 31, 2023 from an expense of $0.7 million for the three months ended March 31, 2022. Other (expense) income, net normally consists of foreign currency gains and (losses) as discussed in Note 1 to the unaudited condensed consolidated financial statements. However, the three months ended March 31, 2023, also included $1.4 million expense from a transition period adjustment of the bargain purchase gain related to the Arrangement with TransGlobe as discussed in Note 3 to our unaudited condensed consolidated financial statements. Foreign currency losses are the primary driver for the activity during the three months ended March 31, 2022.
Income tax expense (benefit) for the three months ended March 31, 2023 was an expense of $14.8 million. This is comprised of current tax expense of $12.3 million and $2.5 million of deferred tax expense. Income tax expense (benefit) for the three months ended March 31, 2022 was a benefit of $4.6 million. This was comprised of $10.3 million of net deferred tax benefit and a current tax expense of $5.7 million.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.
FOREIGN EXCHANGE RISK
Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of March 31, 2023, we had net monetary assets of $22.6 million (XAF 13,642.2 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $2.1 million reduction in the value of these net assets. For the three months ended March 31, 2023, we had expenditures of approximately $11.3 million (net to VAALCO), denominated in XAF.
Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. We estimate that a 10% decrease in the value of the Canadian dollar against the US dollar would increase the value of the net assets for the three months ended March 31, 2023 by approximately $0.8 million. Conversely, a 10% increase in the value of the Canadian dollar against the US dollar would decrease the value of the net assets for the three months ended March 31, 2023 by approximately $0.9 million.
We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates at March 31, 2023, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase the cash value for the three months ended March 31, 2023 by less than $0.1 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the three months ended March 31, 2023 by less than $0.1 million.
COUNTERPARTY RISK
We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparty. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
COMMODITY PRICE RISK
Our major market risk exposure continues to be the prices received for our crude oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low crude oil and natural gas prices or a resumption of the decreases in crude oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.
With respect to our crude oil sales in Gabon, the price received is based on Dated Brent prices plus or minus a differential. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 459 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $2.3 million decrease per quarter in revenues and operating income (loss) and a $2.1 million decrease per quarter in net income (loss).
Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between VAALCO’s recognition of costs and their recovery as VAALCO accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, our share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil.
With respect to our crude oil and NGL sales in Canada, the prices received is based on NYMEX WTI (west Texas Intermediate) prices plus or minus a differential. Natural gas sales are based on Canadian index price that whose price is based, in part. on the NYMEX Henry Hub Natural Gas futures contracts. If Canadian BOE sales were to remain constant at the most recent quarterly sales volumes of 211 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $1.1 million decrease per quarter in revenues and operating income (loss) and a $0.8 million decrease per quarter in net income (loss).
As of March 31, 2023, we had unexpired derivative instruments outstanding covering approximately 287 MBbls of production through June 2023. In April of 2023, we added derivative contracts covering 285 MBbls of production from July 2023 through September 2023. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes. See Note 8 to our unaudited condensed consolidated financial statements for further discussion.
Interest Rate RISK
Changes in market interest rates affect the amount of interest owed on outstanding balances under our Facility. However as of March 31, 2023 we had no amounts drawn under the facility. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. Additionally, changes in market interest rates could impact interest costs associated with any future debt issuances.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of March 31, 2023, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level due to the material weaknesses in control over financial reporting previously disclosed in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
Notwithstanding the identified material weaknesses, management, including our principal executive officer and principal financial officer, believes the consolidated financial statements included in this Quarterly Report on Form 10-Q fairly represent in all material respects our financial condition, results of operations and cash flows at and for the periods presented in accordance with GAAP.
On October 13, 2022, we completed the acquisition of TransGlobe, see Note 3 to the unaudited condensed consolidated financial statements, which operated under its own set of internal controls. During the three months ended March 31, 2023, we transitioned certain TransGlobe processes to our internal control processes and added other internal controls over significant processes specific to the acquisition and to post-acquisition activities, including internal controls associated with the valuation of certain assets acquired and liabilities assumed in the acquisition. We will continue the process of integrating internal control over financial reporting for TransGlobe and plans to incorporate TransGlobe in the evaluation of our disclosure controls and procedures beginning in the second quarter of 2023.
MANAGEMENT’S PLAN FOR REMEDIATION OF THE MATERIAL WEAKNESS
As previously described in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, we began implementing a remediation plan to address the material weaknesses mentioned above. The weaknesses will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expect that the remediation of the material weaknesses will be completed prior to the end of fiscal year 2023.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
Except for the activities taken related to the remediation of the material weaknesses described above, there have been no changes in our internal control over financial reporting during the three months ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that none of the claims and litigation we are currently involved in are material to our business.
Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2022 Form 10-K. There have been no material changes in our risk factors from those described in our 2022 Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sale of Equity Securities
There were no sales of unregistered securities during the quarter ended March 31, 2023 that were not previously reported on a Current Report on Form 8-K.
Dividend Policy
On November 3, 2021, we announced that our board of directors adopted a cash dividend policy.
On February 14, 2023, our board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on March 31, 2023 to stockholders of record at the close of business on March 24, 2023. On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Issuer Repurchases of Common Stock
On November 1, 2022, we announced that our board of directors formally ratified and approved the share buyback program ("the Plan") that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the Plan to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using our cash on hand and cash flow from operations.
The following table represents details of the various repurchases under the Plan during the quarter ended March 31, 2023:
| Period |
Total Number of Shares Purchased |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Programs |
Maximum Amount that May Yet Be Used to Purchase Shares Under the Program |
||||||||||||
| January 1, 2023 - January 31, 2023 |
350,832 | $ | 4.27 | 350,832 | $ | 25,502,669 | ||||||||||
| February 1, 2023 - February 28, 2023 |
326,992 | $ | 4.59 | 326,992 | $ | 24,003,172 | ||||||||||
| March 1, 2023 - March 31, 2023 |
303,176 | $ | 4.95 | 303,176 | $ | 22,503,206 | ||||||||||
| Total |
981,000 | 981,000 | ||||||||||||||
See Note 14 to the unaudited condensed consolidated financial statements for further discussion. Subsequent to March 31, 2023 and through May 9, 2023, the following table represents the details of various repurchases under the Plan:
| Period |
Total Number of Shares Purchased |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Programs |
Maximum Amount that May Yet Be Used to Purchase Shares Under the Program |
||||||||||||
| April 1, 2023 - April 30, 2023 |
303,969 | $ | 4.93 | 303,969 | $ | 21,003,245 | ||||||||||
| May 1, 2023 - May 8, 2023 |
362,843 | $ | 4.14 | 362,843 | $ | 19,502,740 | ||||||||||
| Total |
666,812 | 666,812 | ||||||||||||||
(a) Exhibits
(a) Filed herewith
(b) Furnished herewith
* Management contract or compensatory plan or arrangement.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VAALCO ENERGY, INC.
(Registrant)
| By |
: |
/s/ Ronald Bain |
| Ronald Bain |
||
| Chief Financial Officer (Principal Financial Officer) |
Dated: May 10, 2023
EXHIBIT 31.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO
EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, George W.M. Maxwell, certify that:
|
(1) |
I have reviewed this quarterly report on Form 10-Q of VAALCO Energy, Inc.; |
|
(2) |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
(3) |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
|
(4) |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
|
(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
|
(5) |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
|
(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: May 10, 2023
|
/s/ George W.M. Maxwell |
|
George W.M. Maxwell |
Chief Executive Officer
EXHIBIT 31.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO
EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Ronald Bain, certify that:
|
(1) |
I have reviewed this quarterly report on Form 10-Q of VAALCO Energy, Inc.; |
|
(2) |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
|
(3) |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
|
(4) |
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
(a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
(b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
(c) |
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
|
(d) |
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
|
(5) |
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
|
(a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
|
(b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: May 10, 2023
|
/s/ Ronald Bain |
|
Ronald Bain |
|
Chief Financial Officer (Principal Financial Officer) |
EXHIBIT 32.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of VAALCO Energy, Inc. (the “Company”) on Form 10-Q for the quarterly period ended March 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George W.M. Maxwell, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
|
(1) |
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Dated: May 10, 2023
|
|
|
|
|
/s/ George W.M. Maxell |
|
|
George W.M. Maxwell, Chief Executive Officer |
EXHIBIT 32.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of VAALCO Energy, Inc. (the “Company”) on Form 10-Q for the quarterly period ended March 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ronald Bain, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
|
(1) |
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended; and |
|
(2) |
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Dated: May 10, 2023
|
|
|
|
|
/s/ Ronald Bain |
|
|
Ronald Bain, Chief Financial Officer (Principal Financial Officer) |
Condensed Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
|---|---|---|
| Allowance for accounts with joint ventures | $ 300 | $ 300 |
| Allowance for other receivables | 3,500 | 0 |
| Allowance for value added tax and other receivables | $ 9,000 | $ 8,400 |
| Preferred stock, par value (in dollars per share) | $ 25 | $ 25 |
| Preferred stock, shares authorized (in shares) | 500,000 | 500,000 |
| Preferred stock, shares issued (in shares) | 0 | 0 |
| Common stock, par value (in dollars per share) | $ 0.10 | $ 0.10 |
| Common stock, shares authorized (in shares) | 160,000,000 | 160,000,000 |
| Common stock, shares issued (in shares) | 120,116,106 | 119,482,680 |
| Common stock, shares outstanding (in shares) | 107,318,214 | 107,852,857 |
| Treasury stock, shares (in shares) | 12,797,892 | 11,629,823 |
Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Revenues: | ||
| Crude oil, natural gas and natural gas liquids sales | $ 80,403 | $ 68,656 |
| Operating costs and expenses: | ||
| Production expense | 28,200 | 18,360 |
| Exploration expense | 8 | 127 |
| Depreciation, depletion and amortization | 24,417 | 4,673 |
| General and administrative expense | 5,224 | 4,994 |
| Credit losses and other | 935 | 492 |
| Total operating costs and expenses | 58,784 | 28,646 |
| Other operating expense, net | 0 | (5) |
| Operating income | 21,619 | 40,005 |
| Other income (expense): | ||
| Derivative instruments gain (loss), net | 21 | (31,758) |
| Interest expense, net | (2,246) | (3) |
| Other expense, net | (1,140) | (696) |
| Total other expense, net | (3,365) | (32,457) |
| Income from continuing operations before income taxes | 18,254 | 7,548 |
| Income tax expense (benefit) | 14,771 | (4,628) |
| Income from continuing operations | 3,483 | 12,176 |
| Loss from discontinued operations, net of tax | (13) | (12) |
| Net income | 3,470 | 12,164 |
| Other comprehensive income (loss) | ||
| Currency translation adjustments | (125) | 0 |
| Comprehensive income | $ 3,345 | $ 12,164 |
| Basic net income per share: | ||
| Income from continuing operations (in dollars per share) | $ 0.03 | $ 0.21 |
| Loss from discontinued operations, net of tax (in dollars per share) | 0.00 | 0.00 |
| Net income per share (in dollars per share) | $ 0.03 | $ 0.21 |
| Basic weighted average shares outstanding (in shares) | 107,387 | 58,702 |
| Diluted net income per share: | ||
| Income from continuing operations (in dollars per share) | $ 0.03 | $ 0.20 |
| Loss from discontinued operations, net of tax (in dollars per share) | 0.00 | 0.00 |
| Net income per share (in dollars per share) | $ 0.03 | $ 0.20 |
| Diluted weighted average shares outstanding (in shares) | 108,752 | 59,179 |
Condensed Consolidated Statements of Shareholders' Equity (Unaudited) - USD ($) $ in Thousands |
Cumulative Effect, Period of Adoption, Adjustment [Member]
Common Stock [Member]
|
Cumulative Effect, Period of Adoption, Adjustment [Member]
Treasury Stock, Common [Member]
|
Cumulative Effect, Period of Adoption, Adjustment [Member]
Additional Paid-in Capital [Member]
|
Cumulative Effect, Period of Adoption, Adjustment [Member]
AOCI Attributable to Parent [Member]
|
Cumulative Effect, Period of Adoption, Adjustment [Member]
Retained Earnings [Member]
|
Cumulative Effect, Period of Adoption, Adjustment [Member] |
Common Stock [Member] |
Treasury Stock, Common [Member] |
Additional Paid-in Capital [Member] |
AOCI Attributable to Parent [Member] |
Retained Earnings [Member] |
Total |
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Balance (in shares) at Dec. 31, 2021 | 69,562 | (10,939) | ||||||||||
| Balance at Dec. 31, 2021 | $ 6,956 | $ (43,847) | $ 76,700 | $ 104,488 | $ 144,297 | |||||||
| Shares issued - stock-based compensation (in shares) | 300 | (64) | ||||||||||
| Shares issued - stock-based compensation | $ 30 | $ 0 | 168 | 0 | 198 | |||||||
| Stock-based compensation expense | 0 | $ 0 | 404 | 0 | 404 | |||||||
| Treasury stock (in shares) | 0 | |||||||||||
| Treasury stock | 0 | $ (387) | 0 | 0 | (387) | |||||||
| Dividend Distributions | (1,929) | (1,929) | ||||||||||
| Net income | $ 0 | $ 0 | 0 | $ 0 | 12,164 | 12,164 | ||||||
| Balance (in shares) at Mar. 31, 2022 | 69,862 | (11,003) | ||||||||||
| Balance at Mar. 31, 2022 | $ 6,986 | $ (44,234) | 77,272 | 114,723 | 154,747 | |||||||
| Balance (in shares) at Dec. 31, 2022 | 119,483,000 | (11,630,000) | ||||||||||
| Balance (Accounting Standards Update 2016-13 [Member]) at Dec. 31, 2022 | $ 0 | $ 0 | $ 0 | $ 0 | $ (3,120) | $ (3,120) | ||||||
| Balance at Dec. 31, 2022 | $ 11,948 | $ (47,652) | 353,606 | 1,179 | 147,024 | 466,105 | ||||||
| Shares issued - stock-based compensation (in shares) | 633,000 | (187,000) | ||||||||||
| Shares issued - stock-based compensation | $ 64 | $ 0 | 210 | 0 | 0 | 274 | ||||||
| Stock-based compensation expense | $ 0 | $ 0 | 683 | 0 | 0 | 683 | ||||||
| Common Shares Purchased (in shares) | 0 | (981,000) | ||||||||||
| Common Shares Purchased | $ 0 | $ (4,517) | 0 | 0 | 0 | $ (4,517) | ||||||
| Treasury stock (in shares) | 0 | (981,000) | ||||||||||
| Treasury stock | 0 | $ (860) | 0 | 0 | 0 | $ (860) | ||||||
| Dividend Distributions | (6,735) | (6,735) | ||||||||||
| Other comprehensive loss | 0 | 0 | 0 | (125) | 0 | (125) | ||||||
| Net income | $ 0 | $ 0 | 0 | 0 | 3,470 | 3,470 | ||||||
| Balance (in shares) at Mar. 31, 2023 | 120,116,000 | (12,798,000) | ||||||||||
| Balance at Mar. 31, 2023 | $ 12,012 | $ (53,029) | $ 354,499 | $ 1,054 | $ 140,639 | $ 455,175 |
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |
|---|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
Dec. 31, 2022 |
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| CASH FLOWS FROM OPERATING ACTIVITIES: | |||
| Net income | $ 3,470 | $ 12,164 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | |||
| Loss from discontinued operations, net of tax | 13 | 12 | |
| Depreciation, depletion and amortization | 24,417 | 4,673 | |
| Bargain purchase gain | 1,412 | 0 | |
| Deferred taxes | 2,471 | (10,318) | |
| Unrealized foreign exchange loss | 512 | 116 | |
| Stock-based compensation | 649 | 1,422 | |
| Cash settlements paid on exercised stock appreciation rights | (233) | (205) | |
| Derivative instruments (gain) loss, net | (21) | 31,758 | |
| Cash settlements paid on matured derivative contracts, net | (59) | (12,500) | |
| Cash settlements paid on asset retirement obligations | (123) | 0 | |
| Credit losses and other | 935 | 492 | |
| Other operating loss, net | 0 | 5 | |
| Operational expenses associated with equipment and other | (640) | 240 | |
| Change in operating assets and liabilities: | |||
| Trade receivables | 21,357 | (22,152) | |
| Accounts with joint venture owners | 18,911 | (6,652) | |
| Other receivables | (2,309) | (1,723) | |
| Crude oil inventory | (8,443) | (3,041) | |
| Prepayments and other | 983 | (876) | |
| Value added tax and other receivables | (1,361) | (1,076) | |
| Other long-term assets | 1,051 | (1,452) | |
| Accounts payable | (6,739) | (10,132) | |
| Foreign income taxes receivable/payable | 8,193 | 5,691 | |
| Deferred tax liability | (3,250) | 0 | |
| Accrued liabilities and other | (19,177) | 12,814 | |
| Net cash provided by (used in) continuing operating activities | 42,019 | (740) | |
| Net cash used in discontinued operating activities | (13) | (18) | |
| Net cash provided by (used in) operating activities | 42,006 | (758) | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | |||
| Property and equipment expenditures | (27,700) | (23,148) | |
| Net cash used in continuing investing activities | (27,700) | (23,148) | |
| Net cash used in discontinued investing activities | 0 | 0 | |
| Net cash used in investing activities | (27,700) | (23,148) | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | |||
| Proceeds from the issuances of common stock | 274 | 198 | |
| Dividend distribution | (6,735) | (1,929) | |
| Treasury shares | (5,377) | (387) | |
| Payments of finance lease | (1,701) | 0 | |
| Net cash used in continuing financing activities | (13,539) | (2,118) | |
| Net cash used in discontinued financing activities | 0 | 0 | |
| Net cash used in financing activities | (13,539) | (2,118) | |
| Effects of exchange rate changes on cash | (309) | 0 | |
| NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | 458 | (26,024) | |
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD | 59,776 | 72,314 | $ 72,314 |
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD | 60,234 | 46,290 | $ 59,776 |
| Supplemental disclosure of cash flow information: | |||
| Interest paid, net of amounts capitalized | 1,488 | 0 | |
| Supplemental disclosure of non-cash investing and financing activities: | |||
| Property and equipment additions incurred but not paid at end of period | 39,584 | 26,113 | |
| Recognition of right-of-use finance lease assets and liabilities | $ 1,429 | $ 1,851 | |
Note 1 - Organization and Accounting Policies |
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| Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] |
1. ORGANIZATION AND ACCOUNTING POLICIES
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids ("NGLs") properties. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and hold interests in two production sharing contracts ("PSCs") in Egypt. The Company has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, VAALCO has discontinued operations associated with activities in Angola, West Africa and Yemen.
The Company’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, VAALCO Energy, Inc. (UK Branch), VAALCO Energy (USA), Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC, TransGlobe Energy Corporation, TG Energy UK Ltd, TransGlobe Petroleum International Inc., TG Holdings Yemen Inc., TransGlobe West Bakr Inc., TransGlobe West Gharib Inc., TG Energy Marketing Inc., and TG NW Gharib Inc., TG S Ghazalat Inc.
These condensed consolidated financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.
These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, which includes a summary of the significant accounting policies.
On October 5, 2022, the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries (collectively, "OPEC+") announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022 through December 2023. On April 3, 2023, OPEC+ reaffirmed this reduction and announced additional voluntary reductions totaling 1.2 MMBbls through December 2023 by various members in addition to the 500 MBbls per day voluntary reduction already announced by Russia in February 2023. Included in the 1.2 MMBbls per day reduction was a voluntary reduction by the Gabonese government of 8 MBbls per day. The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives.
The average Brent crude oil price for the three months ended March 31, 2023 was $81 per barrel. The average Brent Crude oil price for the three months ended March 31, 2022, June 30, 2022, September 30, 2022 and December 31, 2022 was $100 per barrel, $113 per barrel, $100 per barrel and $88 per barrel, respectively.
During the year ended December 31, 2022 and continuing into 2023, the Company noticed that the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel and materials have increased. Management believes the ongoing war between Russia and Ukraine and the slowdown of the economy in China and their related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation and higher interest rates are impacting the global supply chain market.
While the current commodity price environment is still favorable and the Company has not experienced material disruptions to its operations as a result of COVID-19 or as result of other forces, including the Russia/Ukraine conflict or slowdown in the Chinese economy affecting the global market or further deteriorations of the global supply chain market may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil, natural gas and NGLs properties.
Principles of consolidation – The accompanying unaudited condensed consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.
Use of estimates – The preparation of the Financial Statements in conformity with GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of crude oil, natural gas and NGLs 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 becomes available.
Cash and cash equivalents – Cash and cash equivalents include deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks.
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 March 31, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in Gabon. Long-term amounts at March 31, 2023 and 2022 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows.
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 unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 10 for further discussion.
On February 28, 2019, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar ("USD") denominated account advised the Company that the bank regulator required transfer of the funds to the Bank Of Central African States (BEAC) which is the Central Bank of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests since they were working on an abandonment fund common policy for the oil and gas Industry as well as the mining industry. As a result, the Company was able to make the annual abandonment funding payment for the years 2019 through 2022 totaling $5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023, after continued discussions with various BEAC and government officials, the Company was allowed to re-establish a USD denominated account and made whole for the original USD amount of $37.3 million that was in the account prior to conversion to a local currency account in 2019.
In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023.
The Company is working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.
Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit losses associated with accounts with joint venture owners, see allowance for credit losses below.
Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.
Other receivables, net – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude oil produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery needs and another contract with the refinery itself to deliver the crude oil. Under the contract with the provider of the crude oil, the third-party provider is entitled to a selling price consistent with the price the Company receives under the terms of the Etame PSC for the delivery of the crude oil to the refinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s March 31, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $16.8 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, a $17.9 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 195 MBbls of purchased crude oil from the supplier in the second half of 2022 and a $2.5 million current liability included in the "Accrued liabilities and other" line item for amounts due to the oil supplier for 32.5 MBbls of crude oil purchased in March 2023.
On January 19, 2022, TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the "Eastern Desert") concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation ("EGPC"). The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15-year development term and a 5-year extension option. Upon execution of the Merged Concession, there was an effective date adjustment owed to the Company for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date, February 1, 2020. The cumulative amount of the effective date adjustment was estimated at $67.5 million and was recorded as part of the TransGlobe Arrangement. During the fourth quarter of 2022, the Company received $17.2 million of the receivable. At March 31, 2023, the remaining $50.3 million was recorded on the condensed consolidated balance sheet in current receivables in the "Other, net" line item. The Company continues to work with the marketing and scheduling department of EGPC, as well as the Ministry, to crystallize cargoes against the back dated receivable.
For credit losses associated with other receivables, see allowance for credit losses below.
Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). For the allowance associated with VAT, see allowance for credit losses and other below. Since VAT is assessed under a foreign taxing authority, the allowance falls outside of the scope of the credit loss standard.
As of March 31, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $22.9 million ($14.9 million, net to VAALCO). As of March 31, 2023, the exchange rate was XAF 602.976 = $1.00. As of December 31, 2022, the outstanding VAT receivable balance, excluding the allowance, was approximately $21.8 million ($13.9 million, net to VAALCO). As of December 31, 2022, the exchange rate was XAF 612.6 = $1.00. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the unaudited condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other expense, net” line item of the condensed consolidated statements of operations and comprehensive income.
Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates.
The Company estimates the current expected credit losses based primarily using an either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected.
The Company has identified the following types of financial assets that are within the scope of ASU 2016-13:
As a result of adopting ASU 2016-13 on January 1, 2023, the Company recognized a $3.1 million provision ($18.2 million other receivable balance excluding the provision) for current expected credit losses on its other receivables related to amounts owed to the Company from the refinery in Gabon through a cumulative effect adjustment offset to retained earnings. During the three months ended March 31, 2023, the Company recorded an additional provision of $0.4 million for the oil delivered to the refinery during the quarter.
Also on January 1, 2023, the Company transferred its $0.3 million provision related to accounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. As of March 31, 2023, the Company has established a credit loss allowance for the full $0.3 million receivable from one of the non-operating partners in Block P offshore Equatorial Guinea. The Company is working with its partner on collecting payment.
During the three months ended March, 31, 2023, the Company recognized an additional $0.6 million provision related to its Value added tax with Gabon.
With respect to the Company’s receivable from the refinery and TVA receivable balances, collection efforts, including remedies provided for in the contracts, are being pursued to collect overdue amounts owed to the Company. The Company is in ongoing discussions with the Ministry of the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances.
The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.
Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored on the FSO at March 31, 2023 or the FPSO at March 31, 2022, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. The Company has made the decision to keep an inventory of crude in Egypt rather than perform direct sales in order to push for an export cargo during the second quarter of 2023. At March 31, 2023, the Company is in an underlift situation in Egypt.
Prepayments and Other – Included in “Prepayments and other” line item of the Company’s March 31, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $1.6 million of prepayments related to royalties in Gabon, $1.9 million in prepaid insurance and other, $3.9 million related to prepaid fuel in Egypt, $2.2 million in advances to contractors, and $5.3 million in other prepaid items.
Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the condensed 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 net realizable value.
Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs 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.
Capitalized Equipment Inventory – Capitalized equipment inventory represents the costs incurred in bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Capitalized equipment inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.
Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (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 block basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block 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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically years for office and miscellaneous equipment and to years for leasehold improvements.
Impairment – The Company reviews the crude oil, natural gas and NGLs producing properties for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly affects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 (as defined in the policy "Fair value" below) inputs that are based upon estimates 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, natural gas and NGLs 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, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil, natural gas and NGLs 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, Canada, Egypt and in Block P in Equatorial Guinea. See Note 7 for further discussion.
Purchase Accounting – On October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.
Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, if a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the condensed consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Finance lease liabilities – current portion” and “Finance lease liabilities – net of current portion” within the condensed consolidated balance sheets.
Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 13 for further discussion.
Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.
Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.
In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to continue its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s on the basis of the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the actual sales proceeds received.
Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.
Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 15 for further discussion.
Foreign currency transactions – The U.S. dollar is the functional currency of most of the Company’s foreign operating subsidiaries. However, in connection with the Company’s acquisition of TransGlobe, the Company acquired TransGlobe’s Canadian operations whose functional currency is the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries' functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Both realized and unrealized foreign exchange gain and losses are recorded within the condensed consolidated statements of operations and comprehensive income line item “Other (expense) income, net”.
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, natural gas and NGLs 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. The Company 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 changes 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 condensed consolidated financial position and results of operations. See Note 16 for further discussion.
Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of the Company's crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations and comprehensive income. See Note 8 for further discussion. Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the internally developed present value of future cash flows model that underlies the fair-value measurement).
Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.
Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments and are considered Level 1 inputs. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.
Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.
Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above, as well as taxes other than income taxes.
Other comprehensive income – All of the Company’s other comprehensive income arises from TransGlobe's Canadian operations whose functional currency is the Canadian dollar. Translation gains and losses occur when translating the financial statements of non-U.S. functional currency operations to the USD. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the consolidated statements of operations and comprehensive income. Translations occur as follows:
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Note 2 - New Accounting Standards |
3 Months Ended |
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Mar. 31, 2023 | |
| Notes to Financial Statements | |
| Accounting Standards Update and Change in Accounting Principle [Text Block] |
2. NEW ACCOUNTING STANDARDS
Adopted
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016-13 is effective for Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As a smaller reporting company, through December 31, 2022, the Company was required to adopt the new standard for the fiscal years beginning after December 15, 2022, including interim periods within those fiscal years.
The Company adopted ASU 2016-13 ("ASC 326") on January 1, 2023 using the modified-retrospective approach. The modified-retrospective approach consists of applying the amendments in ASU 2016-03 through a cumulative-effect adjustment, if required, to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company’s current method and timing of recognizing credit losses is in accordance with ASC 326 and is consistent with the previous method of recognizing credit losses, except for one receivable, which now utilizes the Discounted Cash Flow method for computing its Expected Credit Loss ("ECL"). The Company recorded an ECL allowance of $3.1 million as an opening balance adjustment to retained earnings at January 1, 2023. See Note 1 for further details.
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Note 3 - Acquisitions and Dispositions |
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| Mergers, Acquisitions and Dispositions Disclosures [Text Block] |
3. ACQUISITIONS AND DISPOSITIONS
TransGlobe Merger
On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding common shares of TransGlobe and TransGlobe became a direct wholly owned subsidiary of AcquireCo and an indirect wholly owned subsidiary of the Company pursuant to an arrangement agreement entered into by the Company, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”).
At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive 0.6727 (the “exchange ratio”) of a share of common stock, par value $0.10 per share, of the Company (“VAALCO common stock,” and each share of VAALCO common stock, a “VAALCO share”). The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. The Arrangement resulted in VAALCO stockholders owning approximately 54.5%, and TransGlobe shareholders owning approximately 45.5% of the combined company (the “Combined Company”), calculated based on vested outstanding shares of each company as of the date of the Arrangement Agreement.
Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in the Arab Republic of Egypt and Canada. The Combined Company is a leading African-focused operator with a strong production and reserve base and a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. The transaction qualifies as a business combination under ASC 805, Business Combinations and the Company is the accounting acquiror. The purchase accounting for the business combination has not been completed.
During the three months ended March 31, 2023, the deferred tax liability in Egypt was increased by $1.4 million as of the date of the Arrangement. This resulted in a decrease to the bargain purchase gain of a corresponding $1.4 million for the three months ended March 31, 2023 and is reflected in our condensed consolidated statements of operations in the line, "Other expense, net".
The actual impact of the Arrangement was an increase to “Crude oil, natural gas and NGLs sales” of $43.7 million and $9.7 million of “Net income” in the condensed consolidated statements of operations and comprehensive income for the three months ended March 31, 2023.
All assets and liabilities associated with TransGlobe, including crude oil, natural gas and NGLs properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, October 13, 2022, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using a weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and specific risk adjustment factors based on reserve category discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The purchase price allocation is preliminary pending final determination of the fair values of certain assets and liabilities, primarily the accounts receivable, asset retirement obligations, accounts payable and any contingencies, and any related tax impacts. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, an initial $10.8 million bargain purchase gain was recognized. As a result of the transition period adjustment, the initial bargain purchase gain has been reduced to $9.4 million. The bargain purchase gain was due to the decrease in the share price of VAALCO stock from the time period when the arrangement agreement was signed, July 13, 2022 and the share price at closing, October 13, 2022 while the exchange ratio, of TransGlobe shares converted to VAALCO shares, remained the same.
The unaudited pro forma results presented below have been prepared to give the effect of the TransGlobe Arrangement discussed above on the Company’s results for the three months ended March 31, 2022, as if the Arrangement had been consummated on January 1, 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the TransGlobe Arrangement had been completed on such date or project the Company’s results of operations for any future date or period.
Discontinued Operations - Angola and Yemen
In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three months ended March 31, 2023 and 2022, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.
As part of the Arrangement with TransGlobe, the Company acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S-1. In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S-1. The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income. The Company segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three months ended March 31, 2023, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.
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Note 4 - Segment Information |
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| Segment Reporting Disclosure [Text Block] |
4. SEGMENT INFORMATION
The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s two reportable operating segments is organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker, and management review and evaluate the operation of each geographic segment separately, primarily based on operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments.
Segment activity of continuing operations for the three months ended March 31, 2023 and 2022 as well as long-lived assets and segment assets at March 31, 2023 and December 31, 2022 are as follows:
(1) - Includes assets acquired in the TransGlobe acquisition
(1) - Includes assets acquired in the TransGlobe acquisition
Information about the Company’s most significant customers
The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The Company was previously party to a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through July 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. This COSPA has been terminated.
As discussed further in Note 11, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an initial aggregate maximum principal amount available of up to $50.0 million. In connection with the entry into the Facility Agreement, the Company entered into a COSMA with Glencore pursuant to which the Company agreed to make Glencore the exclusive offtaker and marketer of all of the crude oil produced from the Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of the Facility (as defined in the Facility Agreement). Pursuant to the COSMA, Glencore agreed to buy and market the Company’s crude oil with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
For the three months ended March 31, 2023 sales of crude oil to Glencore made up 100% of Etame revenues. For the three months ended March 31, 2022 sales of crude oil to ExxonMobil Sales and Supply LLC made up 100% of Etame revenues. For the three months ended March 31, 2023, Mercuria covered 100% of the Company’s crude oil sales in Egypt. For the three months ended March 31, 2023, revenues in Canada were concentrated in two separate customers that constituted approximately 59% and 21% of revenues. Concentrations of accounts receivable are similar to the revenue percentages.
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Note 5 - Earnings Per Share |
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| Earnings Per Share [Text Block] |
5. EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.
A reconciliation of reported net income to net income used in calculating EPS as well as a reconciliation from basic to diluted shares follows:
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Note 6 - Revenue |
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| Revenue from Contract with Customer [Text Block] |
6. REVENUE
Gabon
Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs or COSMAs. COSPAs or COSMAs 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 or COSMAs. See Note 4 under “Information about the Company’s most significant customers” for further discussion.
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 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% (increasing 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.
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e., the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as operator, 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 volumes sold exceeded the Company’s ownership interest. However, under the COSMA, each coventurer is responsible for invoicing Glencore their respective ownership interest in the final volumes.
For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.
In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame 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% (increasing 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 the corporate income tax liability may be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations and comprehensive income, 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 as a current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, i.e., the period in which it lifts the crude oil.
With respect to the government’sshare 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 and comprehensive income, 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 are 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 Company has a $4.5 million foreign income tax payable as of March 31, 2023 related to Gabon. As of December 31, 2022, the Company had a foreign taxes receivable of $2.8 million, as the Gabonese government lifted more oil-in-kind than what was owed in foreign taxes in December 2022.
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.
Egypt
Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs"). EGPC and the Company’s subsidiary, TransGlobe Petroleum International (“TPI”), each own a 50% interest, respectively, in the operating company which is a party to the Merged Concession Agreement. EGPC and the Company’s subsidiary, TPI, each also own a 50% interest, respectively, in the operating company that is a party to the South Ghazalat concession agreement. 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.
Customer sales generally occur on a daily basis when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. Direct sales to EGPC are considered complete when oil is delivered to EGPC storage facility. When sales are made through cargo lifting, the performance obligations are normally satisfied either when the oil is delivered to the export facility location or when the oil is delivered to its ultimate destination, as specified in the contract. Regardless of the type of sales, there is a single performance obligation (delivering crude oil to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.
Revenues associated with the sales of the Company’s crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, the Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of profit oil or excess cost oil which is discussed below.
Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, the Company's share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically, maximum cost oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically, the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. EGPC’s share of productionwill increase during times of rising oil prices and decrease in times of declining oil prices. If oil prices are sufficiently low and the Gharib Blend/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSCs and any eligible extension periods.
With respect to Egyptian income taxes, which are the Company’s liability under the terms of the Merged Concession Agreement, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense for reporting purposes.
EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30-day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Direct sales to EGPC are normally settled two to four weeks from delivery.
In some instances TPI will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances, TPI can be in an overlift or underlift position. Regardless of being in an over lift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and TPI will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable.
The following table presents revenues in Egypt from contracts with customers:
Canada
Revenues from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. 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. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are measured at the transaction price that the Company expects to be entitled in exchange for transferring promised goods to a customer and is determined based at the fair value of the consideration received. VAALCO pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. For reporting purposes, the Company records revenues net of royalties.
Customer sales generally occur on a daily basis when crude oil, natural gas, condensate or NGL’s are sold, normally via pipeline, to a delivery point. Regardless of the type of sales, there is a single performance obligation (delivering crude oil, natural gas, condensate or NGL’s to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.
Settlement of accounts receivable in Canada occur on the 25th of the following month after production.
The following table presents revenues in Canada from contracts with customers:
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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment |
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| Oil and Gas Properties [Text Block] |
7. CRUDE OIL, NATURAL GAS and NGLs PROPERTIES AND EQUIPMENT
The Company’s crude oil, natural gas and NGLs properties and equipment is comprised of the following:
Etame Marin Block PSC
On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received a Presidential Decree for an extension (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a 63.575% participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.
The PSC Extension extends the term to operate until September 17, 2028. The PSC Extension also grants the Etame Consortium the right for additional extension periods of years each.
In accordance with the Etame Marin block PSC, the Etame Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Under the PSC Extension, the Cost Recovery Percentage increased to 80% for the -year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%. The government of Gabon will acquire from the Etame Consortium an additional 2.5% gross working interest carried by the Etame Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is 1.6%.
Egypt PSCs
On January 20, 2022, the Company announced a fully executed Merged Concession Agreement with EGPC that merged the existing Eastern Desert concessions with a 15-year primary term and improved economics. In connection with the Merged Concession Agreement, the Company is required to make further annual $10.0 million modernization payments from February 2023 through February 2026. In accordance with the Merged Concession, the Company agreed to substitute the February 2023 payment and issue a $10.0 million credit against receivables owed to it from EGPC.
The Merged Concession Agreement contains minimum financial work commitments of $50.0 million per each -year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date").
The Egyptian PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs. Each PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production less cost oil) is shared between the government and the contractor as defined in the specific PSC. The Egyptian PSCs do not contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the contractor's sales volumes. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.
The following table summarizes the Company's Egyptian PSC terms for the first tranche(s) of production for each block. The contracts have different terms for production levels above the first tranche, which are unique to each contract. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche. The Company is the contractor in all of the Company's PSCs.
(1) - Represents the year acquired by TransGlobe, prior to the Arrangement.
Equatorial Guinea PSC
With the approval of the plan of development in September, 2022, the Block P production sharing contract provides for a development and production period of 25 years for the area associated with the Venus development, to September, 2047. The Block P acreage is 23,144 hectares, with 8,476 hectares being the area associated with the Venus development. The Royalty of the PSC is 10% for the first 10,000 bopd, and 11% for the 10,000 bopd to 25,000 bopd tranche. The State’s share of profit oil is 10% to a cumulative production of 25 million bbl. For recovery of between 25 million bbl to 50 million bbl, the State’s share of profit oil increases to 20%. The Contractor is allowed access to cost oil to pay for development and operating costs, with a cost oil maximum of 70%. The PSC is subject to 25% income tax in Equatorial Guinea, with tangible development costs being straight line depreciated for tax purposes over 120 months.
Proved Properties
The Company reviews the crude oil, natural gas and NGLs 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, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.
There was no triggering event in the three months ended March 31, 2023 that would cause the Company to believe the value of crude oil, natural gas and NGLs producing properties should be impaired. Factors considered included higher forward prices from December 31, 2022 and capital expenditures in the period related to its reserves in Gabon, Egypt and Canada.
Undeveloped Leasehold Costs
Equatorial Guinea
VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved the Company's appointment as the operator of Block P on November 12, 2019. The Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million to Compania Nacional de Petroleos de Guinea Ecuatorial, (“GEPetrol”) in the event that there is commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. In April 2021, Crown Energy, who held a 5% working interest elected to default on its obligations of Block P. On April 12, 2021, the non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties as required by the Joint Operating Agreement. As a result, VAALCO’s working interest increased to 45.9% when the EG MMH approved the fourth amendment to the production sharing contract. In February of 2023, the Company acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases the Company's future payment to GEPetrol to $6.8 million at first commercial production of the Block.
The Company has completed a feasibility study of the development concept of the Venus discovery on Block P. On September 16, 2022, the EG MMH approved the submitted plan of development. Final documents to affect the plan of development are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and was approved effective November 16, 2022. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with updated participating interest. Execution of the Venus development plan has been initiated. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development. As of March 31, 2023, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license.
Gabon
As a result of the PSC extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at March 31, 2023 was $13.7 million.
Egypt and Canada
In connection with the TransGlobe acquisition discussed under Note 3, the Company added $13.6 million and $16.7 million of undeveloped leasehold costs for Egypt and Canada, respectively. The undeveloped leasehold costs were associated to the probable category of reserves. At March 31, 2023, the undeveloped leasehold costs for Egypt was $13.6 million and Canada was $16.7 million.
Capitalized Equipment Inventory
Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating expense, net” line item of the unaudited condensed consolidated statements of operations and comprehensive income but were not material for the three months ended March 31, 2023 and 2022.
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Note 8 - Derivatives and Fair Value |
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| Derivatives and Fair Value [Text Block] |
8. DERIVATIVES AND FAIR VALUE
The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the Company’s exposure to price fluctuations. See the table below for the list of outstanding contracts as of March 31, 2023:
While these derivative instruments are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes. In connection with the RBL facility entered in May 2022, the Company is required to hedge a portion of its anticipated oil production at the time the Company draws down on the borrowing base.
The derivative instruments are measured at fair value using the Income Method. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the derivative instrument contracts’ fair value includes the impact of the counterparty’s non-performance risk.
To mitigate counterparty risk, the Company enters into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
At times, the Company’s counterparties require that it post collateral for changes in the net fair value of the derivative contracts. This cash collateral is reported in the line item "Restricted cash" on the unaudited condensed consolidated balance sheets.
The following table sets forth the loss on derivative instruments on the Company’s unaudited condensed consolidated statements of operations and comprehensive income:
Subsequent Event
On April 3, 2023, the Company entered into additional derivatives contracts for the first quarter of 2023. The details are in the chart below:
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Note 9 - Accrued Liabilities and Other |
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| Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block] |
9. CURRENT ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other balances were comprised of the following:
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Note 10 - Commitments and Contingencies |
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| Commitments and Contingencies Disclosure [Text Block] |
10. COMMITMENTS AND CONTINGENCIES
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, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, an abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. At March 31, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023.
FPSO charter
In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for -year periods beyond September 2020. These elections were made, and the charter was extended through September 2022. On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 and ratified certain decommissioning and demobilization items associated with exiting the contract.
Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022, and other demobilization fees totaling $15.3 million on a gross basis, $8.9 million net to VAALCO Gabon. The Company relinquished control over the FPSO in the fourth quarter of 2022. VAALCO and the owners of the FPSO are negotiating a final settlement of amounts owed to each other and will conclude on the Company’s restricted cash balances associated with the FPSO.
Regulatory and Joint Interest Audits and Related Matters
The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the Company’s petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the Company’s joint operating agreements.
In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years through 2014. The Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the newly appointed representatives to resolve the audit findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.
Between 2019 and 2021, the government of Gabon conducted an audit of the operations in Gabon, covering the years and 2016. The Company received the findings from this audit and has responded to the audit findings and are working with the government of Gabon on the results of the findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity. Dividend Policy On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy.
On , the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on to stockholders of record at the close of business on March 24, 2023. On , the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on to stockholders of record at the close of business on May 24, 2023.
In connection with the RBL facility, discussed in Note 11, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Share Buyback Program
On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.
The following table shows the repurchases of equity securities related to the share repurchase program after January 1, 2023 through March 31, 2023:
The following table shows the repurchases of equity securities related to the share repurchase program after April 1, 2023 through May 9, 2023:
In connection with the RBL facility, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.
The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, the Company's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, the Company’s third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the Plan.
Merged Concession Agreement
On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed concession agreement "Merged Concession Agreement" with the Egyptian General Petroleum Corporation (“EGPC”) that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession, the Company agreed to substitute the February 2023 payment and issue a million credit against receivables owed to it from EGPC. The Company will make three further annual equalization payments of $10.0 million each beginning February 1, 2024 until February 1, 2026. VAALCO recorded modernization payment liabilities of $26.3 million at March 31, 2023. On the unaudited condensed consolidated balance sheet, $9.4 million of the modernization payment liability was recorded in the line item "Accrued liabilities and other" and $17.0 million was recorded in "Other long-term liabilities".
The Company also has minimum financial work commitments of $50.0 million per each -year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date") for a total of $150 million commencing on the Merged Concession Effective Date"). Through March 31, 2023, all investments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.
As the Merged Concession Agreement is effective as of February 1, 2020, there will be effective date adjustment owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date. In accordance with GAAP, the Company has recognized a receivable in connection with the effective date adjustment of $67.5 million as of October 13, 2022, based on historical realized prices. However, the cumulative value to be received as a result of the effective date adjustment is currently being finalized with the EGPC and could result in a range of outcomes based on the final price per barrel negotiated. As of March 31, 2023, $50.3 million of the original $67.5 million receivable is recorded on the unaudited condensed consolidated balance sheet in Receivables-Other, net.
Government Related Receivables
Under the Article 35 of the Etame PSC, the Company can be required to contribute to meeting the domestic market needs of Gabon by delivering to the Government, or another entity designated by the Government, an amount of its crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In October 2021, the Company was notified by the Government to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. In exchange, the Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered.
Since the crude oil produced by the Company is not compatible with the crude oil requirements of the refinery, the Company entered into two contracts (buy/sell arrangements) to fulfill its domestic market needs obligation under the Etame PSC. One contract is to purchase oil from another provider (currently Perenco – the supplier) that produces the compatible oil to meet the needs of the refinery and another contract with the refinery itself (currently Sogara -the buyer and state designee) to deliver the crude oil to the Government.
In November 2022, a receivable from Sogara became past due and the Company has not received payments from the refinery since November 2022. At March 31, 2023 the amount due to the Company from the refinery is $20.3 million. The Company is in ongoing discussions with the Ministry of the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances related to both the receivable from the refinery as well as past due VAT receivable amounts owed to the Company. The Company expects to recover the full amount of receivables owed to it for both the VAT receivable and receivable under the oil supply arrangement, but the terms of recovery have not been finalized.
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Note 11 - Debt |
3 Months Ended |
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Mar. 31, 2023 | |
| Notes to Financial Statements | |
| Debt Disclosure [Text Block] |
11. DEBT
As of March 31, 2023 and December 31, 2022, the Company had no outstanding debt.
RBL Facility
On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.
The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves in Gabon and a portion of the Company's proved undeveloped reserves in Gabon. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.
Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).
Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.
The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of March 31, 2023, the Company's borrowing base was $50.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. With regard to the requirement that the Company deliver its fiscal year 2022 annual financial statements to Glencore within 90 days of the end of each fiscal year, the Company requested and received an extension until April 17, 2023. The Company delivered the annual financial statements, along with its covenant compliance certificate to Glencore on April 11, 2023. At March 31, 2023, the Company was in compliance with all other debt covenants and had no outstanding borrowings under the facility.
The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).
Deferred financing costs incurred in connection with securing the Facility were $1.8 million, ($2.1 million net of accumulated amortization of $0.3 million) which is carried in the accompanying unaudited condensed consolidated balance sheets in the line item "Other long-term assets" and is amortized on a straight-line basis, which approximates the effective interest method, over the term of the Facility and included in interest expense in the accompanying unaudited condensed consolidated statements of operations and comprehensive income.
ATB Facility
In connection with the Arrangement with TransGlobe in October 2022, and prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owed under TransGlobe’s credit facility with ATB Financial (the "ATB Facility"), representing approximately Canadian $4.1 million. On January 5, 2023, the ATB Facility was formally closed. Termination of the ATB Facility will not affect the Company's $50.0 million senior secured reserve-based revolving credit facility with Glencore.
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Note 12 - Leases |
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| Operating and Finance Leases [Text Block] |
12. LEASES
Under the leasing standard that became effective January 1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.
Practical Expedients
The Company elected to use all the practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1, 2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption.
Operating leases
The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and equipment and a drilling rig used in the Company’s Egyptian operations.. The duration for these agreements ranges from 3 to 24 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for marine vessels, and certain equipment used in the joint operations includes the gross amount of the lease components.
The marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.
Financing leases
The Company is currently a party to several financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The duration for these agreements ranges from 7 to 114 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities..
All leases
For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it will extend the lease beyond the initial lease term. When the Company believes it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.
For the three months ended March 31, 2023 and 2022, the components of the lease costs and the supplemental information were as follows:
The table below describes the presentation of the total lease cost on the Company’s unaudited condensed consolidated statements of operations and comprehensive income. 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.
The following table describes the future maturities of the Company’s lease liabilities at March 31, 2023:
Under the joint operating agreements, other joint venture owners are obligated to fund $51.5 million of the $125.0 million in future lease liabilities.
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Note 13 - Asset Retirement Obligations |
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| Asset Retirement Obligation Disclosure [Text Block] |
13. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations:
Accretion is recorded in the line item “Depreciation, depletion and amortization” in the unaudited condensed consolidated statements of operations and comprehensive income.
In connection with the TransGlobe Arrangement in October 2022, as discussed in Note 3, the Company added million of ARO for the future abandonment and reclamation costs of the Canadian assets. The Egypt concessions have no ARO.
With relation to the end of the FPSO contract in October 2022, the Company incurred decommissioning settlement fees totaling $6.6 million previously recorded in the asset retirement obligations and included on the consolidated statements of cash flows in the line item, "Cash settlements paid on asset retirement obligations".
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 prepared in November 2021. As a result of the expected timing of the end of the FPSO contract, included in the line item "Accrued liabilities and other" in the unaudited condensed consolidated balance sheet is $0.3 million of costs associated with the retirement obligation as of March 31, 2023.
In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.
In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor may be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism. At December 31, 2022, no asset retirement obligation is recorded associated with the Egypt PSCs.
The Company provides for asset retirement obligations on all of its Canadian operations based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The estimated ARO liability for Canada includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as using inflation factors and discount rates in order to calculate the amount of the ARO liability.
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Note 14 - Shareholders' Equity |
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| Equity [Text Block] |
14. SHAREHOLDERS’ EQUITY
Common stock
On October 13, 2022, in connection with the closing of the Arrangement, (i) the total number of authorized shares of common stock of the Company was increased from 100 million shares to 160 million shares and (ii) VAALCO issued approximately 49.3 million shares to TransGlobe's shareholders.
Preferred stock
Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of March 31, 2023.
Treasury stock
On November 1, 2022, the Company announced that the board of directors formally ratified and approved a share buyback program. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations. See Note 10 for further discussion.
The below table shows the repurchases of the Company's equity securities during the three months ended March 31, 2023:
For the majority of restricted stock awards granted by the Company, the number of shares issued to the participant on the vesting date are net of shares withheld to meet applicable tax withholding requirements. In addition, when options are exercised, the participant may elect to remit shares to the Company to cover the tax liability and the cost of the exercised options. When this happens, the Company adds these shares to treasury stock and pays the taxes on the participant’s behalf.
Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in the Company's financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 15 for further discussion.
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Note 15 - Stock-based Compensation and Other Benefit Plans |
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| Share-Based Payment Arrangement [Text Block] |
15. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS
The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s board of directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At March 31, 2023, under the 2020 Plan, 3,989,458 shares were available for future grants.
For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the three months ended March 31, 2023, the Company settled in cash $0.2 million for stock appreciation rights and received $0.3 million for stock option exercises. During the three months ended March 31, 2022, the Company settled in cash $0.2 million for stock appreciation rights and received $0.2 million for stock option exercises.
Stock options and performance shares
Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors that is generally a -year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.
The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option.
For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.
During the three months ended March 31, 2022, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo. No options were granted in the first quarter of 2023.
Stock option activity associated with the Monte Carlo model for the three months ended March 31, 2023 is provided below:
Stock option activity associated with the Black-Scholes model for the three months ended March 31, 2023 is provided below:
As a result of tax withholding on options exercised, 22,027 shares were added to treasury during the three months ended March 31, 2023.
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a -year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). The vesting of the restricted stock is dependent upon, among other things, the employees’ and directors’ continued service with the Company.
The following is a summary of activity for the three months ended March 31, 2023:
During the three months ended March 31, 2023, 55,600 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.
In connection with the Arrangement with TransGlobe and pursuant to the Arrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of cash or TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021 and 64.4% for PSUs granted in 2022.
RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the Arrangement. Each RSU vests annually over a -year period. On December 16, 2022, Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of RSU activity for the three months ended March 31, 2023:
During the three months ended March 31, 2023, 45,186 shares were added to treasury as a result of tax withholding on the vesting of RSU’s.
PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021; and 64.4% for PSUs granted in 2022. All PSUs granted vest on the anniversary of their grant date. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of PSU activity for the three months ended March 31, 2023:
During the three months ended March 31, 2023, 64,256 shares were added to treasury as a result of tax withholding on the vesting of PSU’s.
DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's Board of Directors. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. At March 31, 2023, approximately 460,000 DSUs are vested but not distributed. No grants, vestings, distributions or forfeitures occurred in the first quarter of 2023 related to DSUs.
Stock appreciation rights (“SARs”)
SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s board of directors.
During the three months ended March 31, 2023, the Company did grant SARs to employees or directors.
SAR activity for the three months ended March 31, 2023 is provided below:
Other Benefit Plans
The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive 100% and 50%, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75% of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.
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Note 16 - Income Taxes |
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| Income Tax Disclosure [Text Block] |
16. INCOME TAXES
VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions that include Canada, Egypt, Equatorial Guinea and Gabon.
Income taxes attributable to continuing operations for the three months ended March 31, 2023 and 2022 are attributable to foreign taxes payable in Gabon and Egypt, as well as income taxes in the U.S.
Provision for income taxes related to income from continuing operations consists of the following:
The Company’s effective tax rate for the three months ended March 31, 2023 and 2022, excluding the impact of discrete items, was 60.96% and 67.9%, respectively. The total tax expense for the three months ended March 31, 2023, includes a discrete amount of $4.6 million primarily related to adjustments made as a result of changes to oil price adjustments. For the three months ended March 31, 2023, the current tax expense of $12.3 million includes a $3.2 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding that impact, current income taxes were an expense of $9.1 million for the period. For the three months ended March 31, 2022, the current tax expense of $ 5.7 million includes a $3.1 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $2.6 million for the period
As of March 31, 2023, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.
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Note 17 - Other Comprehensive Income |
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17. OTHER COMPREHENSIVE INCOME
The Company’s other comprehensive loss was $0.1 million for the three months ended March 31, 2023. The functional currency of TransGlobe Energy Corporation is the Canadian Dollar. All of the Company’s other comprehensive income arises from the currency translation of TransGlobe Energy Corporation to USD.
The components of accumulated other comprehensive income are as follows:
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Significant Accounting Policies (Policies) |
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| Consolidation, Policy [Policy Text Block] | Principles of consolidation – The accompanying unaudited condensed consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.
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| Use of Estimates, Policy [Policy Text Block] | Use of estimates – The preparation of the Financial Statements in conformity with GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of crude oil, natural gas and NGLs 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 becomes available.
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| Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and cash equivalents – Cash and cash equivalents include deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks.
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| Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | 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 March 31, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in Gabon. Long-term amounts at March 31, 2023 and 2022 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows.
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 unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 10 for further discussion.
On February 28, 2019, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar ("USD") denominated account advised the Company that the bank regulator required transfer of the funds to the Bank Of Central African States (BEAC) which is the Central Bank of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests since they were working on an abandonment fund common policy for the oil and gas Industry as well as the mining industry. As a result, the Company was able to make the annual abandonment funding payment for the years 2019 through 2022 totaling $5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023, after continued discussions with various BEAC and government officials, the Company was allowed to re-establish a USD denominated account and made whole for the original USD amount of $37.3 million that was in the account prior to conversion to a local currency account in 2019.
In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023.
The Company is working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.
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| Interest in Unincorporated Joint Ventures or Partnerships, Policy [Policy Text Block] | Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit losses associated with accounts with joint venture owners, see allowance for credit losses below.
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| Accounts Receivable [Policy Text Block] | Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.
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| Other Receivables [Policy Text Block] | Other receivables, net – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude oil produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery needs and another contract with the refinery itself to deliver the crude oil. Under the contract with the provider of the crude oil, the third-party provider is entitled to a selling price consistent with the price the Company receives under the terms of the Etame PSC for the delivery of the crude oil to the refinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s March 31, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $16.8 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, a $17.9 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 195 MBbls of purchased crude oil from the supplier in the second half of 2022 and a $2.5 million current liability included in the "Accrued liabilities and other" line item for amounts due to the oil supplier for 32.5 MBbls of crude oil purchased in March 2023.
On January 19, 2022, TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the "Eastern Desert") concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation ("EGPC"). The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15-year development term and a 5-year extension option. Upon execution of the Merged Concession, there was an effective date adjustment owed to the Company for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date, February 1, 2020. The cumulative amount of the effective date adjustment was estimated at $67.5 million and was recorded as part of the TransGlobe Arrangement. During the fourth quarter of 2022, the Company received $17.2 million of the receivable. At March 31, 2023, the remaining $50.3 million was recorded on the condensed consolidated balance sheet in current receivables in the "Other, net" line item. The Company continues to work with the marketing and scheduling department of EGPC, as well as the Ministry, to crystallize cargoes against the back dated receivable.
For credit losses associated with other receivables, see allowance for credit losses below.
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| Taxes and Other Receivables [Policy Text Block] | Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). For the allowance associated with VAT, see allowance for credit losses and other below. Since VAT is assessed under a foreign taxing authority, the allowance falls outside of the scope of the credit loss standard.
As of March 31, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $22.9 million ($14.9 million, net to VAALCO). As of March 31, 2023, the exchange rate was XAF 602.976 = $1.00. As of December 31, 2022, the outstanding VAT receivable balance, excluding the allowance, was approximately $21.8 million ($13.9 million, net to VAALCO). As of December 31, 2022, the exchange rate was XAF 612.6 = $1.00. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the unaudited condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other expense, net” line item of the condensed consolidated statements of operations and comprehensive income.
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| Credit Loss, Financial Instrument [Policy Text Block] | Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates.
The Company estimates the current expected credit losses based primarily using an either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected.
The Company has identified the following types of financial assets that are within the scope of ASU 2016-13:
As a result of adopting ASU 2016-13 on January 1, 2023, the Company recognized a $3.1 million provision ($18.2 million other receivable balance excluding the provision) for current expected credit losses on its other receivables related to amounts owed to the Company from the refinery in Gabon through a cumulative effect adjustment offset to retained earnings. During the three months ended March 31, 2023, the Company recorded an additional provision of $0.4 million for the oil delivered to the refinery during the quarter.
Also on January 1, 2023, the Company transferred its $0.3 million provision related to accounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. As of March 31, 2023, the Company has established a credit loss allowance for the full $0.3 million receivable from one of the non-operating partners in Block P offshore Equatorial Guinea. The Company is working with its partner on collecting payment.
During the three months ended March, 31, 2023, the Company recognized an additional $0.6 million provision related to its Value added tax with Gabon.
With respect to the Company’s receivable from the refinery and TVA receivable balances, collection efforts, including remedies provided for in the contracts, are being pursued to collect overdue amounts owed to the Company. The Company is in ongoing discussions with the Ministry of the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances.
The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.
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| Inventory, Policy [Policy Text Block] | Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored on the FSO at March 31, 2023 or the FPSO at March 31, 2022, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. The Company has made the decision to keep an inventory of crude in Egypt rather than perform direct sales in order to push for an export cargo during the second quarter of 2023. At March 31, 2023, the Company is in an underlift situation in Egypt.
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| Prepayments and Other [Policy Text Block] | Prepayments and Other – Included in “Prepayments and other” line item of the Company’s March 31, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $1.6 million of prepayments related to royalties in Gabon, $1.9 million in prepaid insurance and other, $3.9 million related to prepaid fuel in Egypt, $2.2 million in advances to contractors, and $5.3 million in other prepaid items.
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| Inventory Supplies, Policy [Policy Text Block] | Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the condensed 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 net realizable value.
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| Oil and Gas Properties Policy [Policy Text Block] | Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs 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.
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| Exploratory Drilling Costs Capitalization and Impairment, Policy [Policy Text Block] | Capitalized Equipment Inventory – Capitalized equipment inventory represents the costs incurred in bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Capitalized equipment inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.
Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (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.
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| Depreciation, Depletion, and Amortization [Policy Text Block] | Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block 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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically years for office and miscellaneous equipment and to years for leasehold improvements.
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| Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] | Impairment – The Company reviews the crude oil, natural gas and NGLs producing properties for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly affects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 (as defined in the policy "Fair value" below) inputs that are based upon estimates 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, natural gas and NGLs 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, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil, natural gas and NGLs 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, Canada, Egypt and in Block P in Equatorial Guinea. See Note 7 for further discussion.
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| Business Combinations Policy [Policy Text Block] | Purchase Accounting – On October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.
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| Lessee, Leases [Policy Text Block] | Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, if a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the condensed consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Finance lease liabilities – current portion” and “Finance lease liabilities – net of current portion” within the condensed consolidated balance sheets.
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| Asset Retirement Obligation [Policy Text Block] | Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 13 for further discussion.
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| Revenue from Contract with Customer [Policy Text Block] | Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.
Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.
In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to continue its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s on the basis of the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the actual sales proceeds received.
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| Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block] | 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.
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| Share-Based Payment Arrangement [Policy Text Block] | Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 15 for further discussion.
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| Foreign Currency Transactions and Translations Policy [Policy Text Block] | Foreign currency transactions – The U.S. dollar is the functional currency of most of the Company’s foreign operating subsidiaries. However, in connection with the Company’s acquisition of TransGlobe, the Company acquired TransGlobe’s Canadian operations whose functional currency is the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries' functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Both realized and unrealized foreign exchange gain and losses are recorded within the condensed consolidated statements of operations and comprehensive income line item “Other (expense) income, net”.
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| Income Tax, Policy [Policy Text Block] | 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, natural gas and NGLs 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. The Company 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 changes 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 condensed consolidated financial position and results of operations. See Note 16 for further discussion.
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| Derivatives, Policy [Policy Text Block] | Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of the Company's crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations and comprehensive income. See Note 8 for further discussion. |
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| Fair Value Measurement, Policy [Policy Text Block] | 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).
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| Nonrecurring Fair Value Measurements [Policy Text Block] | Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.
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| Fair Value of Financial Instruments, Policy [Policy Text Block] | 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, accrued liabilities, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments and are considered Level 1 inputs. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.
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| Earnings Per Share, Policy [Policy Text Block] | Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.
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| Other Net Policy [Policy Text Block] | Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above, as well as taxes other than income taxes.
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| Comprehensive Income, Policy [Policy Text Block] | Other comprehensive income – All of the Company’s other comprehensive income arises from TransGlobe's Canadian operations whose functional currency is the Canadian dollar. Translation gains and losses occur when translating the financial statements of non-U.S. functional currency operations to the USD. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the consolidated statements of operations and comprehensive income. Translations occur as follows:
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Note 1 - Organization and Accounting Policies (Tables) |
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| Notes Tables | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Cash, Cash Equivalents and Restricted Cash [Table Text Block] |
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| Accounts Receivable, Allowance for Credit Loss [Table Text Block] |
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| Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] |
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Note 3 - Acquisitions and Dispositions (Tables) |
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| Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] |
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| Business Acquisition, Pro Forma Information [Table Text Block] |
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Note 4 - Segment Information (Tables) |
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| Schedule of Segment Reporting Information, by Segment [Table Text Block] |
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| Reconciliation of Assets from Segment to Consolidated [Table Text Block] |
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Note 5 - Earnings Per Share (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Weighted Average Number of Shares [Table Text Block] |
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Note 6 - Revenue (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Disaggregation of Revenue [Table Text Block] |
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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Property, Plant and Equipment [Table Text Block] |
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| Collaborative Arrangement and Arrangement Other than Collaborative [Table Text Block] |
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| Crude Oil Production [Table Text Block] |
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Note 8 - Derivatives and Fair Value (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] |
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| Schedule of Derivative Instruments [Table Text Block] |
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Note 9 - Accrued Liabilities and Other (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] |
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Note 10 - Commitments and Contingencies (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Commitments [Table Text Block] |
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Note 12 - Leases (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Lease, Cost [Table Text Block] |
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| Summary of Lease Costs in Consolidated Statements of Operations [Table Text Block] |
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Note 13 - Asset Retirement Obligations (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Change in Asset Retirement Obligation [Table Text Block] |
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Note 14 - Shareholders' Equity (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Stockholders Equity [Table Text Block] |
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Note 15 - Stock-based Compensation and Other Benefit Plans (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Share-Based Payment Arrangement, Expensed and Capitalized, Amount [Table Text Block] |
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| Nonvested Restricted Stock Shares Activity [Table Text Block] |
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| Share-Based Payment Arrangement, Performance Shares, Activity [Table Text Block] |
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Note 16 - Income Taxes (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] |
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Note 17 - Other Comprehensive Income (Tables) |
3 Months Ended | |||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 | ||||||||||||||||||||||||||
| Notes Tables | ||||||||||||||||||||||||||
| Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] |
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Note 1 - Organization and Accounting Policies (Details Textual) $ in Thousands |
1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Jan. 12, 2023
USD ($)
|
Jan. 01, 2023
USD ($)
|
Jan. 19, 2022
USD ($)
|
Mar. 31, 2023
USD ($)
|
Mar. 31, 2023
USD ($)
$ / item
|
Dec. 31, 2022
USD ($)
$ / item
|
Sep. 30, 2022
$ / item
|
Jun. 30, 2022
$ / item
|
Mar. 31, 2022
USD ($)
$ / item
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
Oct. 13, 2022
USD ($)
|
|
| Oil and Gas, Average Sale Price (in USD per Per Share) | $ / item | 81 | 88 | 100 | 113 | 100 | |||||||
| Payments for Abandonment Funding | $ 15,600 | $ 0 | ||||||||||
| Abandonment Funding Payment Due | $ 5,800 | |||||||||||
| Reestablishment of Currency Denominated Account | $ 37,300 | |||||||||||
| Abandonment Funding Payment Approved | $ 26,600 | 26,600 | ||||||||||
| Abandonment Funding Payment Approved, Attributable to Company | 15,600 | 15,600 | ||||||||||
| Payment Received for Abandonment | 15,600 | |||||||||||
| Value Added Tax Receivable | 14,900 | 14,900 | 13,900 | |||||||||
| Accounts Receivable, Credit Loss Expense (Reversal) | 935 | $ 492 | ||||||||||
| Provision for Doubtful Accounts Transferred | 300 | |||||||||||
| Accounts Receivable, Allowance for Credit Loss | 12,832 | 12,832 | 8,704 | $ 6,135 | $ 5,741 | |||||||
| Prepayments for Fixed Assets | 2,500 | 2,500 | ||||||||||
| Prepaid Insurance | 1,900 | 1,900 | ||||||||||
| Advances to Contractors | 2,200 | 2,200 | ||||||||||
| Other Prepaid Expense, Current | $ 5,300 | $ 5,300 | ||||||||||
| Office Equipment [Member] | Maximum [Member] | ||||||||||||
| Property, Plant and Equipment, Useful Life (Year) | 5 years | 5 years | ||||||||||
| Leasehold Improvements [Member] | Maximum [Member] | ||||||||||||
| Property, Plant and Equipment, Useful Life (Year) | 7 years | 7 years | ||||||||||
| Leasehold Improvements [Member] | Minimum [Member] | ||||||||||||
| Property, Plant and Equipment, Useful Life (Year) | 5 years | 5 years | ||||||||||
| GABON | ||||||||||||
| Prepaid Royalties | $ 1,600 | $ 1,600 | ||||||||||
| EGYPT | ||||||||||||
| Prepaid Fuel | 3,900 | 3,900 | ||||||||||
| Tax Administration of Gabon [Member] | ||||||||||||
| Provision for Value Added Tax | 600 | |||||||||||
| Block P Offshore Equatorial Guinea [Member] | ||||||||||||
| Accounts Receivable, Allowance for Credit Loss | $ 300 | 300 | ||||||||||
| Oil Delivery [Member] | ||||||||||||
| Accounts Receivable, Credit Loss Expense (Reversal) | $ 400 | |||||||||||
| Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member] | ||||||||||||
| Other Receivables | $ 18,200 | |||||||||||
| Accounts Receivable, Credit Loss Expense (Reversal) | 3,100 | |||||||||||
| Accounts Receivable, Allowance for Credit Loss | $ 3,100 | $ 3,120 | $ (0) | |||||||||
| Communaute Financiere Africaine BEAC, Francs | ||||||||||||
| Foreign Currency Exchange Rate, Translation | 602.976 | 602.976 | 612.6 | |||||||||
| Canada, Dollars | ||||||||||||
| Foreign Currency Exchange Rate, Translation | 0.738 | 0.738 | 0.739 | |||||||||
| Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | ||||||||||||
| Value Added Tax Receivable | $ 22,900 | $ 22,900 | $ 21,800 | |||||||||
| TransGlobe [Member] | ||||||||||||
| Merged Concession Agreement, Development Term (Year) | 15 years | |||||||||||
| Merged Concession Agreement, Extension Term (Year) | 5 years | |||||||||||
| Other Receivables | $ 67,500 | 50,300 | 50,300 | $ 67,500 | ||||||||
| Proceeds From Other Receivables | $ 17,200 | |||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||||||||
| Accounts Payable, Other, Current | 17,900 | 17,900 | ||||||||||
| Other Accrued Liabilities, Current | 2,500 | 2,500 | ||||||||||
| Other, Net [Member] | ||||||||||||
| Accounts Receivable, after Allowance for Credit Loss | $ 16,800 | $ 16,800 | ||||||||||
| Purchase Commitment [Member] | ||||||||||||
| Number of Contracts Entered Into | 2 | |||||||||||
Note 1 - Organization and Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
Mar. 31, 2022 |
|---|---|---|---|
| Cash and cash equivalents | $ 52,119 | $ 18,939 | |
| Restricted cash | 76 | $ 222 | 4,230 |
| Restricted cash - non-current | 1,771 | 1,763 | 1,752 |
| Abandonment funding | 6,268 | $ 20,586 | 21,369 |
| Total cash, cash equivalents and restricted cash | $ 60,234 | $ 46,290 |
Note 1 - Organization and Accounting Policies - Analysis of Change in Allowance for Bad Debt (Details) - USD ($) $ in Thousands |
3 Months Ended | ||
|---|---|---|---|
Jan. 01, 2023 |
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Balance at beginning of period | $ (8,704) | $ (8,704) | $ (5,741) |
| Credit loss charges and other, net of receipts | (935) | (492) | |
| Foreign currency gain (loss) | (73) | 98 | |
| Balance at end of period | (12,832) | (6,135) | |
| Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member] | |||
| Balance at beginning of period | (3,120) | $ (3,120) | $ 0 |
| Credit loss charges and other, net of receipts | (3,100) | ||
| Balance at end of period | $ (3,100) | ||
Note 1 - Organization and Accounting Policies - Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
|---|---|---|
| Assets, Fair Value Disclosure | $ 124 | $ 102 |
| Liabilities, Fair Value Disclosure | 297 | 556 |
| Assets, Fair Value Disclosure | 124 | 102 |
| Liabilities, Fair Value Disclosure | 297 | 556 |
| Prepayments and Other [Member] | ||
| Derivative asset | 124 | 102 |
| Accrued Liabilities and Other [Member] | ||
| SARs liability | 297 | 556 |
| Fair Value, Inputs, Level 1 [Member] | ||
| Assets, Fair Value Disclosure | 0 | 0 |
| Liabilities, Fair Value Disclosure | 0 | 0 |
| Assets, Fair Value Disclosure | 0 | 0 |
| Liabilities, Fair Value Disclosure | 0 | 0 |
| Fair Value, Inputs, Level 1 [Member] | Prepayments and Other [Member] | ||
| Derivative asset | 0 | 0 |
| Fair Value, Inputs, Level 1 [Member] | Accrued Liabilities and Other [Member] | ||
| SARs liability | 0 | 0 |
| Fair Value, Inputs, Level 2 [Member] | ||
| Assets, Fair Value Disclosure | 124 | 102 |
| Liabilities, Fair Value Disclosure | 297 | 556 |
| Assets, Fair Value Disclosure | 124 | 102 |
| Liabilities, Fair Value Disclosure | 297 | 556 |
| Fair Value, Inputs, Level 2 [Member] | Prepayments and Other [Member] | ||
| Derivative asset | 124 | 102 |
| Fair Value, Inputs, Level 2 [Member] | Accrued Liabilities and Other [Member] | ||
| SARs liability | 297 | 556 |
| Fair Value, Inputs, Level 3 [Member] | ||
| Assets, Fair Value Disclosure | 0 | 0 |
| Liabilities, Fair Value Disclosure | 0 | 0 |
| Assets, Fair Value Disclosure | 0 | 0 |
| Liabilities, Fair Value Disclosure | 0 | 0 |
| Fair Value, Inputs, Level 3 [Member] | Prepayments and Other [Member] | ||
| Derivative asset | 0 | 0 |
| Fair Value, Inputs, Level 3 [Member] | Accrued Liabilities and Other [Member] | ||
| SARs liability | $ 0 | $ 0 |
Note 2 - New Accounting Standards (Details Textual) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Jan. 01, 2023 |
Dec. 31, 2022 |
Mar. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|---|---|---|
| Accounts Receivable, Allowance for Credit Loss | $ 12,832 | $ 8,704 | $ 6,135 | $ 5,741 | |
| Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member] | |||||
| Accounts Receivable, Allowance for Credit Loss | $ 3,100 | $ 3,120 | $ (0) |
Note 3 - Acquisitions and Dispositions (Details Textual) $ / shares in Units, shares in Millions, $ in Millions |
3 Months Ended | |||
|---|---|---|---|---|
|
Oct. 13, 2022
USD ($)
$ / shares
shares
|
Mar. 31, 2023
USD ($)
$ / shares
|
Dec. 31, 2022
$ / shares
|
Nov. 30, 2006 |
|
| Common Stock, Par or Stated Value Per Share (in dollars per share) | $ / shares | $ 0.10 | $ 0.10 | $ 0.10 | |
| Block 5 PSA [Member] | ||||
| Equity Method Investment, Ownership Percentage | 40.00% | |||
| Equity Method Investment, Additional Working Interest Percentage | 10.00% | |||
| Excluded From ProForma [Member] | TransGlobe [Member] | ||||
| Asset Impairment Charges | $ 26.0 | |||
| VAALCO Energy [Member] | VAALCO Stockholders [Member] | ||||
| Estimated Ownership to Be Received, Percent | 54.50% | |||
| VAALCO Energy [Member] | TransGlobe Shareholders [Member] | ||||
| Estimated Ownership to Be Received, Percent | 45.50% | |||
| TransGlobe [Member] | ||||
| Business Acquisition, Exchange Ratio | 0.6727 | |||
| Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (in shares) | shares | 49.3 | |||
| Business Combination, Bargain Purchase, Increase (Decrease) of Gain Recognized, Amount | 1.4 | |||
| Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 43.7 | |||
| Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | 9.7 | |||
| Business Combination, Bargain Purchase, Gain Recognized, Amount | $ 10.8 | 9.4 | ||
| TransGlobe [Member] | Foreign Tax Authority [Member] | Egyptian Tax Authority [Member] | ||||
| Business Combination, Deferred Tax Liability Assumed | $ 1.4 |
Note 3 - Acquisitions and Dispositions - Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - TransGlobe [Member] $ in Thousands |
Oct. 13, 2022
USD ($)
|
|---|---|
| Common stock issued to TransGlobe shareholders | $ 274,145 |
| Cash | 36,686 |
| Wells, platforms and other production facilities | 243,669 |
| Equipment and other | 2,099 |
| Undeveloped acreage | 30,216 |
| Accounts receivable - trade | 48,068 |
| Accounts receivable - other | 50,275 |
| Accounts with joint venture owners | 68 |
| Right of use operating leases | 1,609 |
| Right of use financing leases | 204 |
| Prepayment and other | 7,627 |
| Asset retirement obligations | (6,134) |
| Accounts payable | (10,223) |
| Accrued liabilities and other | (50,128) |
| Operating lease liabilities - current portion | (961) |
| Financing lease liabilities - current portion | (125) |
| Operating lease liabilities - net of current portion | (688) |
| Financing lease liabilities - net of current portion | (21) |
| Deferred tax liabilities | (40,964) |
| Other long-term liabilities | (26,313) |
| Bargain purchase gain | (10,819) |
| Total purchase price | 274,145 |
| Cumulative Effect, Period of Adoption, Adjusted Balance [Member] | |
| Common stock issued to TransGlobe shareholders | 274,145 |
| Cash | 36,686 |
| Wells, platforms and other production facilities | 243,669 |
| Equipment and other | 2,099 |
| Undeveloped acreage | 30,216 |
| Accounts receivable - trade | 48,068 |
| Accounts receivable - other | 50,275 |
| Accounts with joint venture owners | 68 |
| Right of use operating leases | 1,609 |
| Right of use financing leases | 204 |
| Prepayment and other | 7,627 |
| Asset retirement obligations | (6,134) |
| Accounts payable | (10,223) |
| Accrued liabilities and other | (50,128) |
| Operating lease liabilities - current portion | (961) |
| Financing lease liabilities - current portion | (125) |
| Operating lease liabilities - net of current portion | (688) |
| Financing lease liabilities - net of current portion | (21) |
| Deferred tax liabilities | (42,376) |
| Other long-term liabilities | (26,313) |
| Bargain purchase gain | (9,407) |
| Total purchase price | 274,145 |
| Cumulative Effect, Period of Adoption, Adjustment [Member] | |
| Deferred tax liabilities | (1,412) |
| Bargain purchase gain | $ 1,412 |
Note 3 - Acquisition and Dispositions - Unaudited Proforma Results (Details) - Etame Marine Block [Member] $ / shares in Units, shares in Thousands |
3 Months Ended | |||||||
|---|---|---|---|---|---|---|---|---|
|
Mar. 31, 2023
USD ($)
$ / shares
shares
| ||||||||
| Crude oil, natural gas and natural gas liquids sales | $ 121,127 | [1] | ||||||
| Operating income | 61,427,000 | [2] | ||||||
| Net income | $ 31,039,000 | [3] | ||||||
| Basic net income per share: (in dollars per share) | $ / shares | $ 0.29 | |||||||
| Basic weighted average shares outstanding (in shares) | shares | 108,009 | |||||||
| Diluted net income per share: (in dollars per share) | $ / shares | $ 0.29 | |||||||
| Diluted weighted average shares outstanding (in shares) | shares | 108,486 | |||||||
| ||||||||
Note 4 - Segment Information (Details Textual) $ in Millions |
3 Months Ended | ||
|---|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
May 16, 2022
USD ($)
|
|
| Number of Reportable Segments | 2 | ||
| Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Glencore [Member] | Oil and Gas [Member] | |||
| Concentration Risk, Percentage | 100.00% | ||
| Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Exxon [Member] | Oil and Gas [Member] | |||
| Concentration Risk, Percentage | 100.00% | ||
| Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Customer One [Member] | CANADA | |||
| Concentration Risk, Percentage | 59.00% | ||
| Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Customer Two [Member] | CANADA | |||
| Concentration Risk, Percentage | 21.00% | ||
| Geographic Concentration Risk [Member] | Revenue Benchmark [Member] | Mercuria [Member] | Oil and Gas [Member] | EGYPT | |||
| Concentration Risk, Percentage | 100.00% | ||
| Revolving Credit Facility [Member] | |||
| Line of Credit Facility, Maximum Borrowing Capacity | $ 50 | ||
Note 4 - Segment Information - Segment Activity of Continuing Operations (Details) - USD ($) $ in Thousands |
3 Months Ended | ||||
|---|---|---|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
||||
| Crude oil, natural gas and natural gas liquids sales | $ 80,403 | $ 68,656 | |||
| Production expense | 28,200 | 18,360 | |||
| Exploration expense | 8 | 127 | |||
| Depreciation, depletion and amortization | 24,417 | 4,673 | |||
| General and administrative expense | 5,224 | 4,994 | |||
| Accounts Receivable, Credit Loss Expense (Reversal) | 935 | 492 | |||
| Total operating costs and expenses | 58,784 | 28,646 | |||
| Operating income (loss) | 21,619 | 40,005 | |||
| Derivative instruments gain (loss), net | 21 | (31,758) | |||
| Interest expense, net | (2,246) | (3) | |||
| Other expense, net | (1,140) | (696) | |||
| Total other expense, net | (3,365) | (32,457) | |||
| Income (loss) from continuing operations before income taxes | 18,254 | 7,548 | |||
| Income tax expense | 14,771 | (4,628) | |||
| Income (loss) from continuing operations | 3,483 | 12,176 | |||
| Loss from discontinued operations, net of tax | (13) | (12) | |||
| Net income | 3,470 | 12,164 | |||
| Consolidated capital expenditures | 25,425 | [1] | 31,780 | ||
| Crude oil and natural gas sales | 80,403 | 68,656 | |||
| Production expense | 28,200 | 18,360 | |||
| Exploration expense | 8 | 127 | |||
| General and administrative expense | 5,224 | 4,994 | |||
| Total operating costs and expenses | 58,784 | 28,646 | |||
| Other operating expense, net | 0 | (5) | |||
| Derivative instruments loss, net | 21 | (31,758) | |||
| Interest (expense) income, net | (2,246) | (3) | |||
| Other expense, net | (1,140) | (696) | |||
| Total other expense, net | (3,365) | (32,457) | |||
| Income from continuing operations before income taxes | 18,254 | 7,548 | |||
| Income (loss) from continuing operations | 3,483 | 12,176 | |||
| Loss from discontinued operations, net of tax | (13) | (12) | |||
| Net income (loss) | 3,470 | 12,164 | |||
| Consolidated capital expenditures | 25,425 | [1] | 31,780 | ||
| Corporate, Non-Segment [Member] | |||||
| Crude oil, natural gas and natural gas liquids sales | 0 | 0 | |||
| Production expense | 59 | 60 | |||
| Exploration expense | 0 | 0 | |||
| Depreciation, depletion and amortization | 66 | 20 | |||
| General and administrative expense | 4,298 | 4,302 | |||
| Accounts Receivable, Credit Loss Expense (Reversal) | 0 | 0 | |||
| Total operating costs and expenses | 4,423 | 4,382 | |||
| Operating income (loss) | (4,423) | (4,382) | |||
| Derivative instruments gain (loss), net | 21 | (31,758) | |||
| Interest expense, net | 73 | 3 | |||
| Other expense, net | (1,656) | (57) | |||
| Total other expense, net | (1,562) | (31,812) | |||
| Income (loss) from continuing operations before income taxes | (5,985) | (36,194) | |||
| Income tax expense | 3,201 | (12,486) | |||
| Income (loss) from continuing operations | (9,186) | (23,708) | |||
| Loss from discontinued operations, net of tax | (13) | (12) | |||
| Net income | (9,199) | (23,720) | |||
| Consolidated capital expenditures | 0 | [1] | 0 | ||
| Crude oil and natural gas sales | 0 | 0 | |||
| Production expense | 59 | 60 | |||
| Exploration expense | 0 | 0 | |||
| General and administrative expense | 4,298 | 4,302 | |||
| Total operating costs and expenses | 4,423 | 4,382 | |||
| Other operating expense, net | 0 | ||||
| Derivative instruments loss, net | 21 | (31,758) | |||
| Interest (expense) income, net | 73 | 3 | |||
| Other expense, net | (1,656) | (57) | |||
| Total other expense, net | (1,562) | (31,812) | |||
| Income from continuing operations before income taxes | (5,985) | (36,194) | |||
| Income (loss) from continuing operations | (9,186) | (23,708) | |||
| Loss from discontinued operations, net of tax | (13) | (12) | |||
| Net income (loss) | (9,199) | (23,720) | |||
| Consolidated capital expenditures | 0 | [1] | 0 | ||
| Gabon Segment [Member] | Operating Segments [Member] | |||||
| Crude oil, natural gas and natural gas liquids sales | 36,737 | 68,656 | |||
| Production expense | 14,415 | 18,081 | |||
| Exploration expense | 8 | 127 | |||
| Depreciation, depletion and amortization | 9,845 | 4,653 | |||
| General and administrative expense | 618 | 593 | |||
| Accounts Receivable, Credit Loss Expense (Reversal) | 935 | 492 | |||
| Total operating costs and expenses | 25,821 | 23,946 | |||
| Operating income (loss) | 10,916 | 44,705 | |||
| Derivative instruments gain (loss), net | 0 | 0 | |||
| Interest expense, net | (1,507) | (6) | |||
| Other expense, net | 517 | (638) | |||
| Total other expense, net | (990) | (644) | |||
| Income (loss) from continuing operations before income taxes | 9,926 | 44,061 | |||
| Income tax expense | 6,578 | 7,858 | |||
| Income (loss) from continuing operations | 3,348 | 36,203 | |||
| Loss from discontinued operations, net of tax | 0 | 0 | |||
| Net income | 3,348 | 36,203 | |||
| Consolidated capital expenditures | 3,689 | [1] | 31,780 | ||
| Crude oil and natural gas sales | 36,737 | 68,656 | |||
| Production expense | 14,415 | 18,081 | |||
| Exploration expense | 8 | 127 | |||
| General and administrative expense | 618 | 593 | |||
| Total operating costs and expenses | 25,821 | 23,946 | |||
| Other operating expense, net | (5) | ||||
| Derivative instruments loss, net | 0 | 0 | |||
| Interest (expense) income, net | (1,507) | (6) | |||
| Other expense, net | 517 | (638) | |||
| Total other expense, net | (990) | (644) | |||
| Income from continuing operations before income taxes | 9,926 | 44,061 | |||
| Income (loss) from continuing operations | 3,348 | 36,203 | |||
| Loss from discontinued operations, net of tax | 0 | 0 | |||
| Net income (loss) | 3,348 | 36,203 | |||
| Consolidated capital expenditures | 3,689 | [1] | 31,780 | ||
| Egypt [Member] | Operating Segments [Member] | |||||
| Crude oil, natural gas and natural gas liquids sales | 34,784 | ||||
| Production expense | 11,110 | ||||
| Exploration expense | 0 | ||||
| Depreciation, depletion and amortization | 10,795 | ||||
| General and administrative expense | 179 | ||||
| Accounts Receivable, Credit Loss Expense (Reversal) | 0 | ||||
| Total operating costs and expenses | 22,084 | ||||
| Operating income (loss) | 12,700 | ||||
| Interest expense, net | (808) | ||||
| Other expense, net | 0 | ||||
| Total other expense, net | (808) | ||||
| Income (loss) from continuing operations before income taxes | 11,892 | ||||
| Income tax expense | 4,992 | ||||
| Income (loss) from continuing operations | 6,900 | ||||
| Loss from discontinued operations, net of tax | 0 | ||||
| Net income | 6,900 | ||||
| Consolidated capital expenditures | [1] | 11,571 | |||
| Crude oil and natural gas sales | 34,784 | ||||
| Production expense | 11,110 | ||||
| Exploration expense | 0 | ||||
| General and administrative expense | 179 | ||||
| Total operating costs and expenses | 22,084 | ||||
| Interest (expense) income, net | (808) | ||||
| Other expense, net | 0 | ||||
| Total other expense, net | (808) | ||||
| Income from continuing operations before income taxes | 11,892 | ||||
| Income (loss) from continuing operations | 6,900 | ||||
| Loss from discontinued operations, net of tax | 0 | ||||
| Net income (loss) | 6,900 | ||||
| Consolidated capital expenditures | [1] | 11,571 | |||
| Canada [Member] | Operating Segments [Member] | |||||
| Crude oil, natural gas and natural gas liquids sales | 8,882 | ||||
| Production expense | 2,254 | ||||
| Exploration expense | 0 | ||||
| Depreciation, depletion and amortization | 3,711 | ||||
| General and administrative expense | 0 | ||||
| Accounts Receivable, Credit Loss Expense (Reversal) | 0 | ||||
| Total operating costs and expenses | 5,965 | ||||
| Operating income (loss) | 2,917 | ||||
| Interest expense, net | (4) | ||||
| Other expense, net | 0 | ||||
| Total other expense, net | (4) | ||||
| Income (loss) from continuing operations before income taxes | 2,913 | ||||
| Income tax expense | 0 | ||||
| Income (loss) from continuing operations | 2,913 | ||||
| Loss from discontinued operations, net of tax | 0 | ||||
| Net income | 2,913 | ||||
| Consolidated capital expenditures | [1] | 10,165 | |||
| Crude oil and natural gas sales | 8,882 | ||||
| Production expense | 2,254 | ||||
| Exploration expense | 0 | ||||
| General and administrative expense | 0 | ||||
| Total operating costs and expenses | 5,965 | ||||
| Interest (expense) income, net | (4) | ||||
| Other expense, net | 0 | ||||
| Total other expense, net | (4) | ||||
| Income from continuing operations before income taxes | 2,913 | ||||
| Income (loss) from continuing operations | 2,913 | ||||
| Loss from discontinued operations, net of tax | 0 | ||||
| Net income (loss) | 2,913 | ||||
| Consolidated capital expenditures | [1] | 10,165 | |||
| Equatorial Guinea Segment [Member] | Operating Segments [Member] | |||||
| Crude oil, natural gas and natural gas liquids sales | 0 | 0 | |||
| Production expense | 362 | 219 | |||
| Exploration expense | 0 | 0 | |||
| Depreciation, depletion and amortization | 0 | 0 | |||
| General and administrative expense | 129 | 99 | |||
| Accounts Receivable, Credit Loss Expense (Reversal) | 0 | 0 | |||
| Total operating costs and expenses | 491 | 318 | |||
| Operating income (loss) | (491) | (318) | |||
| Derivative instruments gain (loss), net | 0 | ||||
| Interest expense, net | 0 | 0 | |||
| Other expense, net | (1) | (1) | |||
| Total other expense, net | (1) | (1) | |||
| Income (loss) from continuing operations before income taxes | (492) | (319) | |||
| Income tax expense | 0 | 0 | |||
| Income (loss) from continuing operations | (492) | (319) | |||
| Loss from discontinued operations, net of tax | 0 | 0 | |||
| Net income | (492) | (319) | |||
| Consolidated capital expenditures | 0 | [1] | 0 | ||
| Crude oil and natural gas sales | 0 | 0 | |||
| Production expense | 362 | 219 | |||
| Exploration expense | 0 | 0 | |||
| General and administrative expense | 129 | 99 | |||
| Total operating costs and expenses | 491 | 318 | |||
| Other operating expense, net | 0 | ||||
| Derivative instruments loss, net | 0 | ||||
| Interest (expense) income, net | 0 | 0 | |||
| Other expense, net | (1) | (1) | |||
| Total other expense, net | (1) | (1) | |||
| Income from continuing operations before income taxes | (492) | (319) | |||
| Income (loss) from continuing operations | (492) | (319) | |||
| Loss from discontinued operations, net of tax | 0 | 0 | |||
| Net income (loss) | (492) | (319) | |||
| Consolidated capital expenditures | $ 0 | [1] | $ 0 | ||
| |||||
Note 4 - Segment Information - Assets from Continuing Operations (Details) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
[2] | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Long-lived assets from continuing operations | $ 499,953 | [1] | $ 495,272 | |||||||
| Total assets from continuing operations | 823,983 | [3] | 855,641 | |||||||
| Operating Segments [Member] | Gabon Segment [Member] | ||||||||||
| Long-lived assets from continuing operations | 209,127 | [1] | 213,204 | |||||||
| Total assets from continuing operations | 381,009 | [3] | 395,393 | |||||||
| Operating Segments [Member] | Egypt [Member] | ||||||||||
| Long-lived assets from continuing operations | 170,249 | [1] | 168,012 | |||||||
| Total assets from continuing operations | 270,629 | [3] | 293,640 | |||||||
| Operating Segments [Member] | Canada [Member] | ||||||||||
| Long-lived assets from continuing operations | 109,824 | [1] | 103,263 | |||||||
| Total assets from continuing operations | 116,554 | [3] | 110,071 | |||||||
| Operating Segments [Member] | Equatorial Guinea Segment [Member] | ||||||||||
| Long-lived assets from continuing operations | 10,000 | [1] | 10,000 | |||||||
| Total assets from continuing operations | 11,013 | [3] | 10,861 | |||||||
| Corporate, Non-Segment [Member] | ||||||||||
| Long-lived assets from continuing operations | 753 | [1] | 793 | |||||||
| Total assets from continuing operations | $ 44,778 | [3] | $ 45,676 | |||||||
| ||||||||||
Note 5 - Earnings Per Share - Reconciliation of Basic and Diluted EPS and Shares (Details) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Income (loss) from continuing operations | $ 3,483 | $ 12,176 |
| Income from continuing operations attributable to unvested shares | 18 | (140) |
| Numerator for basic | (3,501) | (12,036) |
| Loss from continuing operations attributable to unvested shares | (18) | 0 |
| Numerator for dilutive | 3,483 | 12,036 |
| Loss from discontinued operations, net of tax | (13) | (12) |
| Loss from discontinued operations attributable to unvested shares | 0 | 0 |
| Numerator for basic | (13) | (12) |
| (Income) loss from discontinued operations attributable to unvested shares | 0 | 0 |
| Numerator for dilutive | (13) | (12) |
| Net income (loss) | 3,470 | 12,164 |
| Net income attributable to unvested shares | (29) | (139) |
| Numerator for basic | 3,441 | 12,025 |
| Net (income) loss attributable to unvested shares | (18) | 0 |
| Numerator for dilutive | $ 3,423 | $ 12,025 |
| Basic weighted average shares outstanding (in shares) | 107,387 | 58,702 |
| Effect of dilutive securities (in shares) | 1,365 | 477 |
| Diluted weighted average shares outstanding (in shares) | 108,752 | 59,179 |
| Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive (in shares) | 195 | 139 |
Note 6 - Revenue (Details Textual) - USD ($) $ in Millions |
3 Months Ended | ||
|---|---|---|---|
Mar. 31, 2023 |
Jun. 20, 2026 |
Dec. 31, 2022 |
|
| Recovery Cost Assigned, Percent | 100.00% | ||
| Minimum [Member] | |||
| Recovery Cost Assigned, Percent | 5.00% | ||
| Cost of Oil, Percent | 25.00% | ||
| Allocation of Profit, Percent | 67.00% | ||
| Maximum [Member] | |||
| Recovery Cost Assigned, Percent | 15.00% | ||
| Cost of Oil, Percent | 40.00% | ||
| Allocation of Profit, Percent | 84.00% | ||
| Egyptian General Petroleum Corporation (EGPC), Merged Concession Agreement [Member] | |||
| Ownership Percentage | 50.00% | ||
| Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | |||
| Ownership Percentage | 50.00% | ||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Foreign Tax Authority [Member] | Tax Administration of Gabon [Member] | |||
| Income Taxes Receivable | $ 4.5 | $ 2.8 | |
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | |||
| Working Interest Ownership, Percentage | 7.50% | ||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | Forecast [Member] | |||
| Working Interest Ownership, Percentage | 10.00% | ||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government of Gabon [Member] | |||
| Monthly Royalty Rate, Based on Production at the Published Price | 13.00% |
Note 6 - Revenue - Revenues from Contracts with Customers and Other Items Not Associated with Customer Contracts (Details) - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Crude oil and natural gas sales | $ 80,403 | $ 68,656 |
| Selling costs | (497) | |
| Crude oil, natural gas and natural gas liquids sales | 80,403 | 68,656 |
| CANADA | ||
| Royalties | (1,193) | |
| Crude oil and natural gas sales | 8,882 | |
| Royalties | (1,193) | |
| Crude oil, natural gas and natural gas liquids sales | 8,882 | |
| EGYPT | ||
| Royalties | (19,340) | |
| Crude oil and natural gas sales | 34,784 | |
| Gross sales | 54,621 | |
| Royalties | (19,340) | |
| Crude oil, natural gas and natural gas liquids sales | 34,784 | |
| Revenue | 54,621 | |
| Crude Oil [Member] | CANADA | ||
| Gross sales | 6,654 | |
| Revenue | 6,654 | |
| Gas [Member] | CANADA | ||
| Gross sales | 958 | |
| Revenue | 958 | |
| Crude Oil Sales and Purchase Agreements [Member] | ||
| Sales under the COSPA or COSMA | 42,601 | 76,486 |
| Revenue | 42,601 | 76,486 |
| Natural Gas Liquids [Member] | CANADA | ||
| Sales under the COSPA or COSMA | 2,463 | |
| Revenue | 2,463 | |
| Carried Interest Recoupment [Member] | ||
| Other items reported in revenue not associated with customer contracts | 0 | 1,112 |
| Oil and Gas [Member] | ||
| Royalties | (5,864) | (8,942) |
| Crude oil and natural gas sales | 36,737 | 68,656 |
| Royalties | (5,864) | (8,942) |
| Crude oil, natural gas and natural gas liquids sales | $ 36,737 | $ 68,656 |
Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment (Details Textual) $ in Millions |
1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 20, 2026 |
Jan. 20, 2022
USD ($)
|
Sep. 25, 2018 |
Feb. 28, 2023
USD ($)
|
Sep. 30, 2022
ha
|
Mar. 31, 2023
USD ($)
|
Dec. 31, 2020
USD ($)
|
Sep. 16, 2028 |
Dec. 31, 2022
USD ($)
|
Oct. 13, 2022
USD ($)
|
Apr. 30, 2021 |
Apr. 12, 2021 |
Feb. 25, 2021
USD ($)
|
Mar. 31, 2020
USD ($)
|
Sep. 17, 2018
USD ($)
|
Dec. 31, 2012 |
|
| Block P Offshore Equatorial Guinea [Member] | ||||||||||||||||
| Business Acquisition, Percentage of Voting Interests Acquired | 31.00% | |||||||||||||||
| Additional Ownership Interest Acquired | 12.00% | |||||||||||||||
| Asset Acquisition, Percent Interest Acquired | 43.00% | |||||||||||||||
| Asset Acquisition, Contingent Consideration Arrangements, Range of Outcomes, Value, High | $ 3.1 | |||||||||||||||
| Etame Marine Block [Member] | ||||||||||||||||
| Unproved Oil and Gas Property, Successful Effort Method | $ 2.2 | |||||||||||||||
| EQUATORIAL GUINEA | ||||||||||||||||
| Effective Statutory Income Tax Rate, Percent | 25.00% | |||||||||||||||
| EGYPT | ||||||||||||||||
| Undeveloped Leasehold Value | $ 13.6 | $ 13.6 | ||||||||||||||
| CANADA | ||||||||||||||||
| Undeveloped Leasehold Value | $ 16.7 | $ 16.7 | ||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||||||||||||
| Deferred Tax Assets, Property, Plant and Equipment | $ 18.6 | |||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Signing Bonus [Member] | ||||||||||||||||
| Capitalized Costs, Unproved Properties | 6.7 | |||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Tax Effect [Member] | ||||||||||||||||
| Capitalized Costs, Unproved Properties | $ 7.1 | |||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Forecast [Member] | Etame Marine Block [Member] | ||||||||||||||||
| Increase (Decrease) in Working Interest Ownership Percentage | 1.60% | |||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | ||||||||||||||||
| Entitled Percent for Consortium After Initial Royalty Percentage | 80.00% | |||||||||||||||
| Period of Agreement for Exploitation Areas (Year) | 10 years | |||||||||||||||
| Working Interest Ownership, Percentage | 7.50% | |||||||||||||||
| Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | Forecast [Member] | ||||||||||||||||
| Entitled Percent for Consortium After Initial Royalty Percentage | 70.00% | |||||||||||||||
| Working Interest Ownership, Percentage | 10.00% | |||||||||||||||
| Merged Concession Agreement with EGPC [Member] | ||||||||||||||||
| Number of Concession Agreements Merged | 3 | |||||||||||||||
| Concession Agreement, Term (Year) | 15 years | |||||||||||||||
| Annual Modernization Payments | $ 10.0 | |||||||||||||||
| Credit issued Against Receivables | 10.0 | |||||||||||||||
| Minimum Financial Work Commitments | $ 50.0 | |||||||||||||||
| Financial Work Commitments Duration (Year) | 5 years | |||||||||||||||
| Etame Marine Block [Member] | ||||||||||||||||
| Joint Venture Project, Ownership, Percent | 63.575% | |||||||||||||||
| Unproved Oil and Gas Property, Successful Effort Method | $ 2.3 | |||||||||||||||
| Undeveloped Leasehold Value | $ 13.7 | $ 11.5 | ||||||||||||||
| Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | ||||||||||||||||
| Number of Contract Extension Periods | 2 | |||||||||||||||
| Production License Agreement Term Extended by Government (Year) | 5 years | |||||||||||||||
| Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Forecast [Member] | ||||||||||||||||
| Increase (Decrease) in Working Interest Ownership Percentage | 2.50% | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | ||||||||||||||||
| Joint Venture Project, Ownership, Percent | 60.00% | 45.90% | ||||||||||||||
| Period of Development Area (Year) | 25 years | 25 years | ||||||||||||||
| Area of Land (Hectare) | ha | 23,144 | |||||||||||||||
| Cost Oil Maximum, Percent | 70.00% | |||||||||||||||
| Asset Acquisition, Contingent Consideration Arrangements, Range of Outcomes, Value, High | $ 6.8 | |||||||||||||||
| Joint Venture Project, Additional Working Interest Percentage | 14.10% | |||||||||||||||
| Unproved Oil and Gas Property, Successful Effort Method | $ 10.0 | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | Crown Energy [Member] | ||||||||||||||||
| Working Interest Ownership, Percentage | 5.00% | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | Royalty for the First 10,000 bopd [Member] | ||||||||||||||||
| Percent of Oil Profit | 10.00% | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | Royalty for the 10,000 bopd to 25,000 bopd Tranche [Member] | ||||||||||||||||
| Percent of Oil Profit | 11.00% | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | The States Share of Oil Profit Up to 25 Million bbl [Member] | ||||||||||||||||
| Percent of Oil Profit | 10.00% | |||||||||||||||
| Block P Offshore Equatorial Guinea [Member] | The States Share of Oil Profit Up to 25 to 50 Million bbl [Member] | ||||||||||||||||
| Percent of Oil Profit | 20.00% | |||||||||||||||
| Venus Development [Member] | ||||||||||||||||
| Area of Land (Hectare) | ha | 8,476 | |||||||||||||||
Note 7 - Crude Oil and Natural Gas Properties and Equipment - Schedule of Crude Oil and Natural Gas Properties and Equipment (Details) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
|---|---|---|
| Gross crude oil and natural gas properties, equipment and other | $ 1,527,998 | $ 1,501,935 |
| Accumulated depreciation, depletion, amortization and impairment | (1,028,045) | (1,006,663) |
| Net crude oil and natural gas properties, equipment and other | 499,953 | 495,272 |
| Wells and Related Equipment and Facilities [Member] | ||
| Gross crude oil and natural gas properties, equipment and other | 1,432,823 | 1,406,888 |
| Construction in Progress [Member] | ||
| Gross crude oil and natural gas properties, equipment and other | 0 | 0 |
| Undeveloped Acreage [Member] | ||
| Gross crude oil and natural gas properties, equipment and other | 53,999 | 56,251 |
| Other Capitalized Property Plant and Equipment [Member] | ||
| Gross crude oil and natural gas properties, equipment and other | $ 41,176 | $ 38,796 |
Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment - Contract Terms (Details) |
3 Months Ended | |||
|---|---|---|---|---|
|
Mar. 31, 2023
MMBbls
| ||||
| Merged Concession [Member] | ||||
| Year acquired (1) | 2020 | [1] | ||
| Development (Year) | 5 years | |||
| Maximum cost oil | 40.00% | |||
| Excess cost oil - Contractor | 15.00% | |||
| Operating | 100.00% | |||
| Capital | 6.00% | |||
| Contractor | 30.00% | |||
| Government | 70.00% | |||
| Merged Concession [Member] | Minimum [Member] | ||||
| Production Tranche (MBopd) (Million Barrels of Oil) | 0 | |||
| Merged Concession [Member] | Maximum [Member] | ||||
| Production Tranche (MBopd) (Million Barrels of Oil) | 25 | |||
| Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | ||||
| Year acquired (1) | 2013 | [1] | ||
| Development (Year) | 25 years | |||
| Maximum cost oil | 25.00% | |||
| Excess cost oil - Contractor | 5.00% | |||
| Operating | 100.00% | |||
| Capital | 5.00% | |||
| Contractor | 17.00% | |||
| Government | 83.00% | |||
| Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | Minimum [Member] | ||||
| Production Tranche (MBopd) (Million Barrels of Oil) | 0 | |||
| Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | Maximum [Member] | ||||
| Production Tranche (MBopd) (Million Barrels of Oil) | 5 | |||
| ||||
Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment - Crude Oil Production (Details) |
Mar. 31, 2023 |
|---|---|
| Government [Member] | Less Than or Equal to $40 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 67.00% |
| Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 68.00% |
| Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 69.00% |
| Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 70.00% |
| Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 71.00% |
| Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 68.00% |
| Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 69.00% |
| Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 70.00% |
| Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 71.00% |
| Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 72.00% |
| Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 70.00% |
| Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 71.00% |
| Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 72.00% |
| Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 74.00% |
| Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 76.00% |
| Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 72.50% |
| Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 73.00% |
| Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 74.00% |
| Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 76.00% |
| Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 78.00% |
| Government [Member] | More Than $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 75.00% |
| Government [Member] | More Than $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 76.00% |
| Government [Member] | More Than $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 77.00% |
| Government [Member] | More Than $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 78.00% |
| Government [Member] | More Than $100 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 80.00% |
| Contractor [Member] | Less Than or Equal to $40 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 33.00% |
| Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 32.00% |
| Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 31.00% |
| Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 30.00% |
| Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 29.00% |
| Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 32.00% |
| Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 31.00% |
| Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 30.00% |
| Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 29.00% |
| Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 28.00% |
| Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 30.00% |
| Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 29.00% |
| Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 28.00% |
| Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 26.00% |
| Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 24.00% |
| Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 27.50% |
| Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 27.00% |
| Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 26.00% |
| Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 24.00% |
| Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 22.00% |
| Contractor [Member] | More Than $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member] | |
| Percent of oil production assigned | 25.00% |
| Contractor [Member] | More Than $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member] | |
| Percent of oil production assigned | 24.00% |
| Contractor [Member] | More Than $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member] | |
| Percent of oil production assigned | 23.00% |
| Contractor [Member] | More Than $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member] | |
| Percent of oil production assigned | 22.00% |
| Contractor [Member] | More Than $100 bbl [Member] | More Than 25 MBopd [Member] | |
| Percent of oil production assigned | 20.00% |
Note 8 - Derivatives and Fair Value - Unexpired Barrels (Details) |
Apr. 03, 2023
$ / bbl
bbl
|
Mar. 31, 2023
$ / item
$ / bbl
bbl
|
|---|---|---|
| Commodity Contract One, April 2023 Through June 2023 [Member] | ||
| Barrels (Barrel of Oil) | bbl | 95,500 | |
| Weighted average price put price (in USD per Barrel of Oil) | 65.00 | |
| Weighted average price call price (in USD per Per Share) | $ / item | 100.00 | |
| Commodity Contract July 2023 to September 2023 [Member] | Short [Member] | Forecast [Member] | ||
| Barrels (Barrel of Oil) | bbl | 95,000 | |
| Weighted average price put price (in USD per Barrel of Oil) | 65.00 | |
| Weighted average price call price (in USD per Per Share) | 96.00 |
Note 8 - Derivatives and Fair Value - Gain Loss on Derivative Instruments (Details) - Crude Oil Swaps [Member] - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Derivative instruments loss, net | $ 21 | $ (31,758) |
| Cash Settlements Paid on Matured Derivative Contracts, Net [Member] | ||
| Derivative instruments loss, net | (59) | (12,500) |
| Unrealized Gain (Loss) [Member] | ||
| Derivative instruments loss, net | $ 80 | $ (19,258) |
Note 9 - Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other Balances (Details) - USD ($) $ in Thousands |
Mar. 31, 2023 |
Dec. 31, 2022 |
|---|---|---|
| Accrued accounts payable invoices | $ 21,185 | $ 28,360 |
| Gabon DMO, PID and PIH obligations | 11,569 | 10,509 |
| Capital expenditures | 27,850 | 26,618 |
| Stock appreciation rights – current portion | 297 | 570 |
| Accrued wages and other compensation | 2,626 | 8,161 |
| ARO Obligation | 260 | 306 |
| Egypt modernization payments | 9,373 | 9,933 |
| Excess cost oil payable | 1,297 | 0 |
| Other | 6,250 | 6,935 |
| Total accrued liabilities and other | $ 80,707 | $ 91,392 |
Note 10 - Commitments and Contingencies (Details Textual) |
3 Months Ended | 12 Months Ended | 36 Months Ended | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
May 09, 2023
$ / shares
|
Feb. 14, 2023
$ / shares
|
Nov. 01, 2022
USD ($)
|
Aug. 20, 2022
USD ($)
|
Feb. 01, 2022
USD ($)
|
Jan. 20, 2022
USD ($)
|
Mar. 31, 2023
USD ($)
|
Mar. 31, 2022
USD ($)
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2020
USD ($)
|
Dec. 31, 2016 |
Dec. 31, 2021 |
Feb. 01, 2026
USD ($)
|
Feb. 01, 2025
USD ($)
|
Feb. 28, 2023
USD ($)
|
Oct. 13, 2022
USD ($)
|
Jan. 19, 2022
USD ($)
|
Nov. 30, 2021
USD ($)
|
Sep. 30, 2020 |
|
| Estimated Abandonment Costs | $ 47,800,000 | ||||||||||||||||||
| Abandonment Funding | $ 6,268,000 | $ 21,369,000 | $ 20,586,000 | ||||||||||||||||
| Payments for Abandonment Funding | 15,600,000 | $ 0 | |||||||||||||||||
| Dividends Payable, Amount Per Share (in dollars per share) | $ / shares | $ 0.0625 | ||||||||||||||||||
| Stock Repurchase Program, Authorized Amount | $ 24,003,172 | ||||||||||||||||||
| Increase (Decrease) in Other Receivables | 2,309,000 | $ 1,723,000 | |||||||||||||||||
| Dividends Payable, Date Declared | Feb. 14, 2023 | ||||||||||||||||||
| Dividends Payable, Date to be Paid | Mar. 31, 2023 | ||||||||||||||||||
| Parent Company [Member] | |||||||||||||||||||
| Contractual Obligation, Total | 26,300,000 | ||||||||||||||||||
| Parent Company [Member] | Accrued Liabilities and Other [Member] | |||||||||||||||||||
| Contractual Obligation, Total | 9,400,000 | ||||||||||||||||||
| Parent Company [Member] | Other Long-term Liabilities [Member] | |||||||||||||||||||
| Contractual Obligation, Total | 17,000,000.0 | ||||||||||||||||||
| TransGlobe [Member] | |||||||||||||||||||
| Other Receivables | 50,300,000 | $ 67,500,000 | $ 67,500,000 | ||||||||||||||||
| Egyptian General Petroleum Corporation (EGPC) [Member] | |||||||||||||||||||
| Contractual Obligation, Total | $ 150,000,000 | ||||||||||||||||||
| Increase (Decrease) in Other Receivables | $ (10,000,000.0) | ||||||||||||||||||
| Development Timeframe (Year) | 5 years | ||||||||||||||||||
| Egyptian General Petroleum Corporation (EGPC) [Member] | Minimum [Member] | |||||||||||||||||||
| Contractual Obligation, Total | $ 50,000,000.0 | ||||||||||||||||||
| Sogara [Member] | |||||||||||||||||||
| Other Receivables | 20,300,000 | ||||||||||||||||||
| Share Buyback Program [Member] | |||||||||||||||||||
| Stock Repurchase Program, Authorized Amount | $ 30,000,000 | ||||||||||||||||||
| Stock Repurchase Program, Period in Force (Month) | 20 months | ||||||||||||||||||
| Subsequent Event [Member] | |||||||||||||||||||
| Dividends Payable, Amount Per Share (in dollars per share) | $ / shares | $ 0.0625 | ||||||||||||||||||
| Dividends Payable, Date Declared | May 09, 2023 | ||||||||||||||||||
| Dividends Payable, Date to be Paid | Jun. 23, 2023 | ||||||||||||||||||
| Foreign Tax Authority [Member] | Tax Administration of Gabon [Member] | |||||||||||||||||||
| Income Tax Examination, Year under Examination | 2013 2014 | 2015 2016 | |||||||||||||||||
| FPSO Charter [Member] | |||||||||||||||||||
| Number of Charter Extension Periods | 2 | ||||||||||||||||||
| Charter Day Rates | $ 150,000 | ||||||||||||||||||
| Other Demobilization Fees, Gross | 15,300,000 | ||||||||||||||||||
| Other Demobilization Fees, Net | $ 8,900,000 | ||||||||||||||||||
| Etame Marine Block [Member] | |||||||||||||||||||
| Abandonment Funding | 6,300,000 | ||||||||||||||||||
| Payments for Abandonment Funding | 15,600,000 | ||||||||||||||||||
| Etame Marine Block [Member] | |||||||||||||||||||
| Estimated Abandonment Costs | $ 81,300,000 | ||||||||||||||||||
| Abandonment Funding | 10,700,000 | ||||||||||||||||||
| Payments for Abandonment Funding | $ 26,600,000 | ||||||||||||||||||
| Egyptian General Petroleum Corporation (EGPC) [Member] | Merged Concession Agreement [Member] | |||||||||||||||||||
| Payments for Merger Related Costs, First Modernization Payment | $ 15,000,000.0 | ||||||||||||||||||
| Payments for Merger Related Costs, Signature Bonus | $ 1,000,000.0 | ||||||||||||||||||
| Payments for Merger Related Costs, Second Modernization Payment | $ 10,000,000.0 | ||||||||||||||||||
| Egyptian General Petroleum Corporation (EGPC) [Member] | Merged Concession Agreement [Member] | Forecast [Member] | |||||||||||||||||||
| Contractual Obligation, Total | $ 10,000,000.0 | $ 10,000,000.0 | |||||||||||||||||
Note 10 - Commitments and Contingencies - Schedule of Equity Securities Repurchased (Details) - USD ($) |
1 Months Ended | 3 Months Ended | ||||||
|---|---|---|---|---|---|---|---|---|
May 08, 2023 |
Jan. 01, 2023 |
May 08, 2023 |
Apr. 30, 2023 |
Mar. 31, 2023 |
Feb. 28, 2023 |
Jan. 31, 2023 |
Mar. 31, 2023 |
|
| Number of Shares Purchased (in shares) | 326,992 | 981,000 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.59 | |||||||
| Stock Repurchase Program, Authorized Amount | $ 24,003,172 | |||||||
| Number of Shares Purchased (in shares) | 326,992 | 981,000 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.59 | |||||||
| Authorized Amount | $ 24,003,172 | |||||||
| Shares Purchased as Part of Publicly Announced Programs [Member] | ||||||||
| Number of Shares Purchased (in shares) | 981,000 | 981,000 | ||||||
| Number of Shares Purchased (in shares) | 981,000 | 981,000 | ||||||
| Shares Purchased as Part of Publicly Announced Programs [Member] | Subsequent Event [Member] | ||||||||
| Number of Shares Purchased (in shares) | 666,812 | |||||||
| Number of Shares Purchased (in shares) | 666,812 | |||||||
| Share Repurchase Program [Member] | Subsequent Event [Member] | ||||||||
| Number of Shares Purchased (in shares) | 666,812 | |||||||
| Number of Shares Purchased (in shares) | 666,812 | |||||||
| Common Stock [Member] | ||||||||
| Number of Shares Purchased (in shares) | 303,176 | 350,832 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.27 | ||||||
| Stock Repurchase Program, Authorized Amount | $ 22,503,206 | $ 25,502,669 | $ 22,503,206 | |||||
| Number of Shares Purchased (in shares) | 303,176 | 350,832 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.27 | ||||||
| Authorized Amount | $ 22,503,206 | $ 25,502,669 | 22,503,206 | |||||
| Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member] | ||||||||
| Number of Shares Purchased (in shares) | 350,832 | 303,176 | 326,992 | 350,832 | ||||
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.59 | $ 4.27 | |||||
| Stock Repurchase Program, Authorized Amount | $ 25,502,669 | $ 22,503,206 | $ 24,003,172 | 22,503,206 | ||||
| Number of Shares Purchased (in shares) | 350,832 | 303,176 | 326,992 | 350,832 | ||||
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.59 | $ 4.27 | |||||
| Authorized Amount | $ 25,502,669 | $ 22,503,206 | $ 24,003,172 | $ 22,503,206 | ||||
| Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member] | Subsequent Event [Member] | ||||||||
| Number of Shares Purchased (in shares) | 362,843 | 303,969 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.14 | $ 4.93 | ||||||
| Stock Repurchase Program, Authorized Amount | $ 19,502,740 | $ 19,502,740 | $ 21,003,245 | |||||
| Number of Shares Purchased (in shares) | 362,843 | 303,969 | ||||||
| Average Price Paid per Share (in dollars per share) | $ 4.14 | $ 4.93 | ||||||
| Authorized Amount | $ 19,502,740 | $ 19,502,740 | $ 21,003,245 | |||||
Note 11 - Debt (Details Textual) $ in Thousands, $ in Millions |
1 Months Ended | ||||
|---|---|---|---|---|---|
May 16, 2025 |
May 16, 2022
USD ($)
|
Oct. 31, 2022
CAD ($)
|
Mar. 31, 2023
USD ($)
|
Dec. 31, 2022
USD ($)
|
|
| Long-Term Debt, Total | $ 0 | $ 0 | |||
| Revolving Credit Facility [Member] | |||||
| Line of Credit Facility, Maximum Borrowing Capacity | $ 50,000 | ||||
| The Facility [Member] | Revolving Credit Facility [Member] | |||||
| Line of Credit Facility, Maximum Borrowing Capacity | 50,000 | ||||
| Line of Credit Facility, Maximum Optional Increase in Maximum Borrowing Capacity | 50,000 | ||||
| Line of Credit Facility, Additional Commitment in Maximum Borrowing Capacity, Yearly Decrease | $ 6,250 | ||||
| Line of Credit Facility, Commitment Fee Percentage, Commitments or Borrowing Base Exceeds Outstanding Utilizations | 35.00% | ||||
| Line of Credit Facility, Commitment Fee Percentage, Total Commitments Exceeds Borrowing Base | 20.00% | ||||
| Debt Instrument, Covenant, Maximum Total Net Debt to EBITDA | 3.0 | ||||
| Debt Instrument, Covenant, Minimum Cash and Cash Equivalents | $ 10,000 | ||||
| Line of Credit Facility, Current Borrowing Capacity | 50,000 | ||||
| Long-Term Line of Credit | 0 | ||||
| Debt Issuance Costs, Net | 1,800 | ||||
| Debt Issuance Costs, Gross | 2,100 | ||||
| Amortization of Debt Issuance Costs | $ 300 | ||||
| The Facility [Member] | Revolving Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member] | |||||
| Debt Instrument, Basis Spread on Variable Rate | 6.00% | ||||
| The Facility [Member] | Revolving Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member] | Forecast [Member] | |||||
| Debt Instrument, Basis Spread on Variable Rate | 6.25% | ||||
| ATB Financial [Member] | TransGlobe [Member] | |||||
| Repayments of Long-Term Lines of Credit | $ 4.1 | ||||
| Glencore [Member] | Revolving Credit Facility [Member] | |||||
| Line of Credit Facility, Maximum Borrowing Capacity | $ 50,000 |
Note 12 - Leases (Details Textual) $ in Millions |
Mar. 31, 2023
USD ($)
|
|---|---|
| Oil and Gas Joint Interest Billing Receivables | $ 51.5 |
| Lessee, Operating And Finance Lease Liability, Payments Due | $ 125.0 |
| Minimum [Member] | |
| Lessee, Operating Lease, Term of Contract (Month) | 3 months |
| Lessee, Finance Lease, Term of Contract (Year) | 7 years |
| Maximum [Member] | |
| Lessee, Operating Lease, Term of Contract (Month) | 24 months |
| Lessee, Finance Lease, Term of Contract (Year) | 114 years |
Note 12 - Leases - Components of Lease Costs and Supplemental Information (Details) - USD ($) $ in Thousands |
3 Months Ended | |||||||
|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|||||||
| Finance lease cost (1) | [1] | $ 4,365 | $ 66 | |||||
| Operating lease cost | 583 | 4,196 | ||||||
| Short-term lease cost (2) | [2] | 1,360 | 1,014 | |||||
| Variable lease cost (3) | [3] | 0 | 1,338 | |||||
| Total lease expense | 6,308 | 6,614 | ||||||
| Lease costs capitalized | 48 | 772 | ||||||
| Total lease costs | 6,356 | 7,386 | ||||||
| Financing cash flows attributable to finance leases (in thousands) | $ 1,701 | $ 0 | ||||||
| Weighted-average remaining lease term (in years) (Year) | 9 years 3 months 29 days | 5 years 5 months 1 day | ||||||
| Weighted-average discount rate | 8.13% | 3.54% | ||||||
| Operating cash flows attributable to operating leases (in thousands) | $ 226 | $ 6,551 | ||||||
| Weighted-average remaining lease term (in years) (Year) | 1 year 1 month 20 days | 8 months 23 days | ||||||
| Weighted-average discount rate | 10.29% | 5.83% | ||||||
| ||||||||
Note 12 - Leases - Lease Cost on the Consolidated Statement of Operations (Details) - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Total lease expense | $ 6,325 | $ 6,895 |
| Lease costs capitalized | 31 | 491 |
| Total lease costs | 6,356 | 7,386 |
| Finance Lease Cost [Member] | ||
| Total lease expense | 2,625 | 39 |
| Production Expense [Member] | ||
| Total lease expense | 1,286 | 3,838 |
| General and Administrative Expense [Member] | ||
| Total lease expense | 46 | 16 |
| Lease Costs Billed to Joint Venture Owners [Member] | ||
| Total lease expense | $ 2,368 | $ 3,002 |
Note 12 - Leases - Future Maturities of Lease Liabilities (Details) $ in Thousands |
Mar. 31, 2023
USD ($)
|
|---|---|
| 2023, operating leases | $ 1,829 |
| 2023, finance leases | 10,377 |
| 2024, operating leases | 672 |
| 2024, finance leases | 13,759 |
| 2025, operating leases | 33 |
| 2025, finance leases | 15,559 |
| 2026, operating leases | 0 |
| 2026, finance leases | 16,156 |
| 2027, operating leases | 0 |
| 2027, finance leases | 15,023 |
| Thereafter, operating leases | 0 |
| Thereafter, finance leases | 51,561 |
| Total due, operating leases | 2,534 |
| Total due, finance leases | 122,435 |
| Less: imputed interest, operating leases | 127 |
| Less: imputed interest, finance leases | 35,058 |
| Total lease liabilities, operating leases | 2,407 |
| Total lease liabilities, finance leases | $ 87,377 |
Note 13 - Asset Retirement Obligations (Details Textual) - USD ($) $ in Thousands |
1 Months Ended | 3 Months Ended | 12 Months Ended |
|---|---|---|---|
Oct. 31, 2022 |
Mar. 31, 2023 |
Dec. 31, 2022 |
|
| Asset Retirement Obligation, Liabilities Incurred | $ 6,100 | $ 0 | $ 6,134 |
| Asset Retirement Obligation, Liabilities Settled | 6,600 | 123 | 6,577 |
| Costs Associated With Retirement Obligation, Included In Accrued Liabilities | $ 300 | ||
| EGYPT | |||
| Decommissioning Liability, Noncurrent | $ 0 | $ 0 |
Note 13 - Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
1 Months Ended | 3 Months Ended | 12 Months Ended |
|---|---|---|---|
Oct. 31, 2022 |
Mar. 31, 2023 |
Dec. 31, 2022 |
|
| Beginning balance | $ 42,001 | $ 40,694 | |
| Accretion | 556 | 1,958 | |
| Additions | $ 6,100 | 0 | 6,134 |
| Revisions | 79 | (43) | |
| Settlements | $ (6,600) | (123) | (6,577) |
| Foreign currency gain (loss) | 74 | (165) | |
| Ending balance | $ 42,587 | $ 42,001 |
Note 14 - Shareholders' Equity (Details Textual) - USD ($) |
Nov. 01, 2022 |
Oct. 13, 2022 |
Mar. 31, 2023 |
Feb. 28, 2023 |
Dec. 31, 2022 |
Oct. 12, 2022 |
|---|---|---|---|---|---|---|
| Common Stock, Shares Authorized (in shares) | 160,000,000 | 160,000,000 | 160,000,000 | 100,000,000 | ||
| Preferred Stock, Shares Authorized (in shares) | 500,000 | 500,000 | ||||
| Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 | ||||
| Preferred Stock, Shares Issued (in shares) | 0 | 0 | ||||
| Stock Repurchase Program, Authorized Amount | $ 24,003,172 | |||||
| Stock Repurchase Program 2019 [Member] | ||||||
| Stock Repurchase Program, Authorized Amount | $ 30,000,000 | |||||
| Stock Repurchase Program, Period in Force (Month) | 20 months | |||||
| TransGlobe [Member] | ||||||
| Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (in shares) | 49,300,000 |
Note 14 - Shareholders' Equity - Schedule of Equity Securities Repurchased (Details) - USD ($) |
1 Months Ended | 3 Months Ended | |||
|---|---|---|---|---|---|
Jan. 01, 2023 |
Mar. 31, 2023 |
Feb. 28, 2023 |
Jan. 31, 2023 |
Mar. 31, 2023 |
|
| Number of Shares Purchased (in shares) | 326,992 | 981,000 | |||
| Average Price Paid per Share (in dollars per share) | $ 4.59 | ||||
| Number of Shares Purchased (in shares) | 326,992 | 981,000 | |||
| Authorized Amount | $ 24,003,172 | ||||
| Shares Purchased as Part of Publicly Announced Programs [Member] | |||||
| Number of Shares Purchased (in shares) | 981,000 | 981,000 | |||
| Number of Shares Purchased (in shares) | 981,000 | 981,000 | |||
| Common Stock [Member] | |||||
| Number of Shares Purchased (in shares) | 303,176 | 350,832 | |||
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.27 | |||
| Number of Shares Purchased (in shares) | 303,176 | 350,832 | |||
| Authorized Amount | $ 22,503,206 | $ 25,502,669 | $ 22,503,206 | ||
| Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member] | |||||
| Number of Shares Purchased (in shares) | 350,832 | 303,176 | 326,992 | 350,832 | |
| Average Price Paid per Share (in dollars per share) | $ 4.95 | $ 4.59 | $ 4.27 | ||
| Number of Shares Purchased (in shares) | 350,832 | 303,176 | 326,992 | 350,832 | |
| Authorized Amount | $ 25,502,669 | $ 22,503,206 | $ 24,003,172 | $ 22,503,206 | |
Note 15 - Stock-based Compensation and Other Benefit Plans (Details Textual) - USD ($) $ in Millions |
1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
|---|---|---|---|---|---|---|---|---|
Jun. 30, 2021 |
Mar. 31, 2023 |
Dec. 31, 2022 |
Mar. 31, 2022 |
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
Jun. 25, 2020 |
|
| Proceeds from Stock Options Exercised | $ 0.3 | $ 0.2 | ||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Grants in Period, Gross (in shares) | 0 | |||||||
| Severance Cost as Percentage of Target Bonus | 75.00% | |||||||
| Maximum [Member] | ||||||||
| Severance Cost as Percentage of Salary | 100.00% | |||||||
| Minimum [Member] | ||||||||
| Severance Cost as Percentage of Salary | 50.00% | |||||||
| Stock Appreciation Rights (SARs) [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Share-Based Liabilities Paid | $ 0.2 | $ 0.2 | ||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares) | 0 | |||||||
| Share-Based Payment Arrangement, Option [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year) | 3 years | |||||||
| Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares) | 22,027 | |||||||
| Restricted Stock [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year) | 3 years | |||||||
| Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares) | 55,600 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares) | 0 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested in Period (in shares) | 205,000 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares) | (0) | |||||||
| Performance Share Units (PSUs) [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year) | 3 years | |||||||
| Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares) | 64,256 | |||||||
| Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Target Percentage | 64.40% | |||||||
| Performance Share Units (PSUs) [Member] | Awards Granted, 2021 and 2020 [Member] | ||||||||
| Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Target Percentage | 200.00% | 200.00% | ||||||
| Restricted Stock Units (RSUs) [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year) | 3 years | |||||||
| Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares) | 45,186 | |||||||
| Deferred Share Units [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested, Outstanding (in shares) | 460,000 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares) | 0 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested in Period (in shares) | 0 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares) | 0 | |||||||
| The 2020 Long-Term Incentive Plan [Member] | ||||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Authorized (in shares) | 5,500,000 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Additional Shares Authorized (in shares) | 3,750,000 | |||||||
| Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Available for Grant (in shares) | 3,989,458 | |||||||
Note 15 - Stock-based Compensation and Other Benefit Plans - Stock-based Compensation (Details) - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Total stock-based compensation | $ 649 | $ 1,422 |
| Equity Awards [Member] | ||
| Total stock-based compensation | 675 | 404 |
| Liability Awards [Member] | ||
| Total stock-based compensation | $ (26) | $ 1,018 |
Note 15 - Stock-based Compensation and Other Benefit Plans - Weighted Average Assumptions (Details) |
2 Months Ended |
|---|---|
|
Mar. 31, 2022
$ / shares
| |
| Weighted average exercise price - ($/share) (in dollars per share) | $ 6.41 |
| Expected life in years (Year) | 6 years |
| Average expected volatility | 72.00% |
| Risk-free interest rate | 1.98% |
| Expected dividend yield | 2.30% |
| Weighted average grant date fair value - ($/share) (in dollars per share) | $ 2.84 |
Note 15 - Stock-based Compensation and Other Benefit Plans - Stock Option Activity (Details) $ / shares in Units, $ in Thousands |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
USD ($)
$ / shares
shares
| |
| Granted, number of shares (in shares) | shares | 0 |
| Monte Carle Model [Member] | |
| Outstanding, number of shares (in shares) | shares | 444 |
| Outstanding, weighted average exercise price (in dollars per share) | $ 3.98 |
| Granted, number of shares (in shares) | shares | 0 |
| Granted, weighted average exercise price (in dollars per share) | $ 0 |
| Exercised, number of shares (in shares) | shares | (74) |
| Exercised, weighted average exercise price (in dollars per share) | $ (1.68) |
| Unvested shares forfeited, number of shares (in shares) | shares | 0 |
| Unvested shares forfeited, weighted average exercise price (in dollars per share) | $ 0 |
| Vested shares expired, number of shares (in shares) | shares | 0 |
| Vested shares expired, weighted average exercise price (in dollars per share) | $ 0 |
| Outstanding, number of shares (in shares) | shares | 370 |
| Outstanding, weighted average exercise price (in dollars per share) | $ 4.40 |
| Outstanding, weighted average remaining contractual term (Year) | 8 years 3 months 18 days |
| Outstanding, aggregate intrinsic value | $ | $ 414 |
| Exercisable, number of shares (in shares) | shares | 166 |
| Exercisable, weighted average exercise price (in dollars per share) | $ 3.91 |
| Exercisable, weighted average remaining contractual term (Year) | 8 years 1 month 24 days |
| Exercisable, aggregate intrinsic value | $ | $ 224 |
| Unvested shares forfeited, weighted average exercise price (in dollars per share) | $ (0) |
| Black-scholes Model [Member] | |
| Outstanding, number of shares (in shares) | shares | 387 |
| Outstanding, weighted average exercise price (in dollars per share) | $ 1.86 |
| Granted, number of shares (in shares) | shares | 0 |
| Granted, weighted average exercise price (in dollars per share) | $ 0 |
| Exercised, number of shares (in shares) | shares | (99) |
| Exercised, weighted average exercise price (in dollars per share) | $ (1.50) |
| Unvested shares forfeited, number of shares (in shares) | shares | 0 |
| Unvested shares forfeited, weighted average exercise price (in dollars per share) | $ 0 |
| Vested shares expired, number of shares (in shares) | shares | 0 |
| Vested shares expired, weighted average exercise price (in dollars per share) | $ 0 |
| Outstanding, number of shares (in shares) | shares | 288 |
| Outstanding, weighted average exercise price (in dollars per share) | $ 1.98 |
| Outstanding, weighted average remaining contractual term (Year) | 9 months 21 days |
| Outstanding, aggregate intrinsic value | $ | $ 732 |
| Exercisable, number of shares (in shares) | shares | 288 |
| Exercisable, weighted average exercise price (in dollars per share) | $ 1.98 |
| Exercisable, weighted average remaining contractual term (Year) | 9 months 21 days |
| Exercisable, aggregate intrinsic value | $ | $ 732 |
| Unvested shares forfeited, weighted average exercise price (in dollars per share) | $ 0 |
Note 15 - Stock-based Compensation and Other Benefit Plans - Summary of Activity for Restricted Shares (Details) - Restricted Stock [Member] shares in Thousands |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
$ / shares
shares
| |
| Non-vested shares outstanding (in shares) | shares | 665 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.59 |
| Awards granted (in shares) | shares | 0 |
| Awards granted, weighted average grant date fair value (in dollars per share) | $ / shares | $ 0 |
| Awards vested (in shares) | shares | (205) |
| Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.82 |
| Awards forfeited (in shares) | shares | 0 |
| Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares | $ 0 |
| Non-vested shares outstanding (in shares) | shares | 460 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.49 |
| The 2020 Plan [Member] | |
| Non-vested shares outstanding (in shares) | shares | 383 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Awards vested (in shares) | shares | (121) |
| Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Awards forfeited (in shares) | shares | (23) |
| Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Non-vested shares outstanding (in shares) | shares | 239 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
Note 15 - Stock-based Compensation and Other Benefit Plans - Summary of Activity for Performance Shares (Details) - Performance Shares [Member] - The 2020 Plan [Member] shares in Thousands |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
$ / shares
shares
| |
| Non-vested shares outstanding (in shares) | shares | 690 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Awards vested (in shares) | shares | (134) |
| Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Awards forfeited (in shares) | shares | (36) |
| Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
| Non-vested shares outstanding (in shares) | shares | 520 |
| Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares | $ 4.27 |
Note 15 - Stock-based Compensation and Other Benefit Plans - SAR Activity (Details) - Stock Appreciation Rights (SARs) [Member] $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
USD ($)
$ / shares
shares
| |
| Outstanding, number of underlying shares (in shares) | shares | 202 |
| Outstanding, weighted average exercise price per share (in dollars per share) | $ / shares | $ 1.87 |
| Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares) | shares | 0 |
| Granted, weighted average exercise price per share (in dollars per share) | $ / shares | $ 0 |
| Exercised, number of underlying shares (in shares) | shares | (63) |
| Exercised, weighted average exercise price per share (in dollars per share) | $ / shares | $ 0.86 |
| Unvested SARs forfeited, number of underlying shares (in shares) | shares | 0 |
| Unvested SARs forfeited, weighted average exercise price per share (in dollars per share) | $ / shares | $ 0 |
| Vested SARs expired, number of underlying shares (in shares) | shares | 0 |
| Vested SARs expired, weighted average exercise price per share (in dollars per share) | $ / shares | $ 0 |
| Outstanding, number of underlying shares (in shares) | shares | 139 |
| Outstanding, weighted average exercise price per share (in dollars per share) | $ / shares | $ 2.33 |
| Outstanding, weighted average remaining contractual term (Year) | 11 months 1 day |
| Outstanding, aggregate intrinsic value | $ | $ 304 |
| Exercisable, number of underlying shares (in shares) | shares | 139 |
| Exercisable, weighted average exercise price per share (in dollars per share) | $ / shares | $ 2.33 |
| Exercisable, weighted average remaining contractual term (Year) | 11 months 1 day |
| Exercisable, aggregate intrinsic value | $ | $ 304 |
Note 16 - Income Taxes (Details Textual) - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Effective Income Tax Rate Reconciliation, Percent | 60.96% | 67.90% |
| Valuation Allowance, Deferred Tax Asset, Change in Amount, Discrete Item | $ 4,600 | |
| Current Income Tax Expense (Benefit) | 12,300 | $ 5,700 |
| Income Tax Expense (Benefit), Favorable (Unfavorable) Oil Price Adjustment | (3,200) | (3,100) |
| Current Foreign Income Tax Expense (Benefit), Net Of Oil Price Adjustment | 9,100 | $ 2,600 |
| Unrecognized Tax Benefits | $ 0 | |
Note 16 - Income Taxes - Provision for Income Taxes (Details) - USD ($) $ in Thousands |
3 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Current | $ 0 | $ 0 |
| Deferred | 586 | (12,486) |
| Current | 12,300 | 5,691 |
| Deferred | 1,885 | 2,167 |
| Total | $ 14,771 | $ (4,628) |
Note 17 - Other Comprehensive Income (Details Textual) $ in Millions |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
USD ($)
| |
| Other Comprehensive Income (Loss), Net of Tax | $ (0.1) |
Note 17 - Other Comprehensive Income - Accumulated Other Comprehensive Income (Details) $ in Thousands |
3 Months Ended |
|---|---|
|
Mar. 31, 2023
USD ($)
| |
| Balance | $ 466,105 |
| Balance | 455,175 |
| Accumulated Foreign Currency Adjustment Attributable to Parent [Member] | |
| Balance | 1,179 |
| Accumulated other comprehensive income (loss) before reclassifications | (125) |
| Balance | $ 1,054 |