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Excludes assets acquired in the TransGlobe acquisition. Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts. 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. Includes assets acquired in the TransGlobe acquisition Includes assets acquired in the Sasol acquisition Represents the year acquired by TransGlobe, prior to the Arrangement. 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. The unaudited pro forma operating income for the six months ended June 30, 2022 removes the $26.0 million impairment reversal recorded by TransGlobe in 2022, reclassifies depreciation expense, for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the arrangement based on the purchase price allocation. Represents depreciation and interest associated with financing leases. 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Table of Contents





Washington, D.C. 20549





(Mark One)



For the quarterly period ended June 30, 2023






For the transition period from _______ to _______


Commission File Number 1-32167



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.)


9800 Richmond Avenue

Suite 700

Houston, Texas


(Address of principal executive offices)

(Zip code)


(713) 623-0801

(Registrants 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


New York Stock Exchange

Common Stock


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 Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No   ☐


Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer


Accelerated filer

Non‑accelerated filer


Smaller reporting company

Emerging growth company


If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.         ☐


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).        Yes      No   ☒


As of August 4, 2023, there were outstanding 106,475,814 shares of common stock, $0.10 par value per share, of the registrant. 








Table of Contents






Condensed Consolidated Balance Sheets June 30, 2023 and December 31, 2022


Condensed Consolidated Statements of Operations and Comprehensive Income Three and Six Months Ended June 30, 2023 and 2022


Condensed Consolidated Statements of Shareholders’ Equity Three and Six Months Ended June 30, 2023 and 2022


Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2023 and 2022


Notes to Condensed Consolidated Financial Statements (unaudited)


























As of June 30, 2023


As of December 31, 2022


(in thousands)




Current assets:


Cash and cash equivalents

 $46,186  $37,205 

Restricted cash

  113   222 



Trade, net

  57,360   52,147 

Accounts with joint venture owners, net of allowance for credit losses of $0.5 and $0.3 million, respectively

  216   15,830 

Foreign income taxes receivable


Other, net of allowance for credit losses of $3.5 and $0.0 million, respectively

  66,615   68,519 

Crude oil inventory

  10,800   3,335 

Prepayments and other

  18,077   20,070 

Total current assets

  199,367   200,097 

Crude oil and natural gas properties, equipment and other - successful efforts method, net

  481,740   495,272 

Other noncurrent assets:


Restricted cash

  1,779   1,763 

Value added tax and other receivables, net of allowance of $9.5 million and $8.4 million, respectively

  8,807   7,150 

Right of use operating lease assets

  1,639   2,777 

Right of use finance lease assets

  90,584   90,698 

Deferred tax assets

  37,155   35,432 

Abandonment funding

  6,268   20,586 

Other long-term assets

  1,674   1,866 

Total assets

 $829,013  $855,641 



Current liabilities:


Accounts payable

 $40,716  $59,886 

Accounts with joint venture owners


Accrued liabilities and other

  84,104   91,392 

Operating lease liabilities - current portion

  1,667   2,314 

Finance lease liabilities - current portion

  7,684   7,811 

Foreign income taxes payable


Current liabilities - discontinued operations

  673   687 

Total current liabilities

  153,703   162,090 

Asset retirement obligations

  42,958   41,695 

Operating lease liabilities - net of current portion

  130   686 

Finance lease liabilities - net of current portion

  79,856   78,248 

Deferred tax liabilities

  82,895   81,223 

Other long-term liabilities

  17,465   25,594 

Total liabilities

  377,007   389,536 

Commitments and contingencies (Note 10)


Shareholders’ equity:


Preferred stock, $25 par value; 500,000 shares authorized, none issued


Common stock, $0.10 par value; 160,000,000 shares authorized, 121,205,919 and 119,482,680 shares issued, 106,997,933 and 107,852,857 shares outstanding, respectively

  12,121   11,948 

Additional paid-in capital

  355,206   353,606 

Accumulated other comprehensive income

  3,060   1,179 

Less treasury stock, 14,207,986 and 11,629,823 shares, respectively, at cost

  (59,055)  (47,652)

Retained earnings

  140,674   147,024 

Total shareholders' equity

  452,006   466,105 

Total liabilities and shareholders' equity

 $829,013  $855,641 


See notes to condensed consolidated financial statements.









Three Months Ended June 30,


Six Months Ended June 30,










(in thousands, except per share amounts)



Crude oil, natural gas and natural gas liquids sales

  $ 109,240     $ 110,985     $ 189,643     $ 179,641  

Operating costs and expenses:


Production expense

    38,604       25,475       66,804       43,835  

FPSO Demobilization - Norms Waste Disposal

    5,647             5,647        

Exploration expense

    57       67       65       194  

Depreciation, depletion and amortization

    38,003       8,191       62,420       12,864  

General and administrative expense

    5,395       3,534       10,619       8,528  

Credit losses and other

    680       571       1,615       1,063  

Total operating costs and expenses

    88,386       37,838       147,170       66,484  

Other operating expense, net

    (303 )           (303 )     (5 )

Operating income

    20,551       73,147       42,170       113,152  

Other income (expense):


Derivative instruments gain (loss), net

    31       (9,542 )     52       (41,300 )

Interest expense, net

    (1,703 )     (118 )     (3,949 )     (121 )

Other expense, net

    (537 )     (2,111 )     (1,677 )     (2,807 )

Total other expense, net

    (2,209 )     (11,771 )     (5,574 )     (44,228 )

Income from continuing operations before income taxes

    18,342       61,376       36,596       68,924  

Income tax expense (benefit)

    11,588       46,252       26,359       41,624  

Income from continuing operations

    6,754       15,124       10,237       27,300  

Loss from discontinued operations, net of tax

    (2 )     (20 )     (15 )     (32 )

Net income

  $ 6,752     $ 15,104     $ 10,222     $ 27,268  

Other comprehensive income (loss)


Currency translation adjustments

    2,006             1,881        

Comprehensive income

  $ 8,758     $ 15,104     $ 12,103     $ 27,268  

Basic net income per share:


Income from continuing operations

  $ 0.06     $ 0.25     $ 0.10     $ 0.46  

Loss from discontinued operations, net of tax


Net income per share

  $ 0.06     $ 0.25     $ 0.10     $ 0.46  

Basic weighted average shares outstanding

    106,965       58,925       107,175       58,814  

Diluted net income per share:


Income from continuing operations

  $ 0.06     $ 0.25     $ 0.09     $ 0.45  

Loss from discontinued operations, net of tax


Net income per share

  $ 0.06     $ 0.25     $ 0.09     $ 0.45  

Diluted weighted average shares outstanding

    107,613       59,361       108,050       59,278  


See notes to condensed consolidated financial statements.









Common Shares Issued


Treasury Shares


Common Stock


Additional Paid-In Capital


Accumulated Other Comprehensive Loss


Treasury Stock


Retained Earnings




(in thousands)


Balance at January 1, 2023

    119,483       (11,630 )   $ 11,948     $ 353,606     $ 1,179     $ (47,652 )   $ 147,024     $ 466,105  

Shares issued - stock-based compensation

    633       (187 )     64       210                         274  

Stock-based compensation expense

                      683                         683  

Common shares purchased

          (981 )                       (4,517 )           (4,517 )

Treasury stock

                                  (860 )           (860 )

Dividend distributions

                                        (6,735 )     (6,735 )

Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023

                                        (3,120 )     (3,120 )

Other comprehensive loss

                            (125 )                 (125 )

Net income

                                        3,470       3,470  

Balance at March 31, 2023

    120,116       (12,798 )   $ 12,012     $ 354,499     $ 1,054     $ (53,029 )   $ 140,639     $ 455,175  

Shares issued - stock-based compensation

    1,090       (249 )     109       (1 )                       108  

Stock-based compensation expense

                      708                         708  

Common shares purchased

          (1,161 )                       (5,023 )           (5,023 )

Treasury stock

                                  (1,003 )           (1,003 )

Dividend distributions

                                        (6,717 )     (6,717 )

Other comprehensive loss

                            2,006                   2,006  

Net income

                                        6,752       6,752  

Balance at June 30, 2023

    121,206       (14,208 )   $ 12,121     $ 355,206     $ 3,060     $ (59,055 )   $ 140,674     $ 452,006  



Common Shares Issued


Treasury Shares


Common Stock


Additional Paid-In Capital


Accumulated Other Comprehensive Loss


Treasury Stock


Retained Earnings




(in thousands)


Balance at January 1, 2022

    69,562       (10,939 )   $ 6,956     $ 76,700     $     $ (43,847 )   $ 104,488     $ 144,297  

Shares issued - stock-based compensation

    300       (64 )     30       168                         198  

Stock-based compensation expense

                      404                         404  

Treasury stock

                                  (387 )           (387 )

Dividend Distributions

                                          (1,929 )     (1,929 )

Net income

                                        12,164       12,164  

Balance at March 31, 2022

    69,862       (11,003 )   $ 6,986     $ 77,272     $     $ (44,234 )   $ 114,723     $ 154,747  

Shares issued - stock-based compensation

    263       (54 )     27       31                         58  

Stock-based compensation expense

                      616                         616  

Treasury stock

                                  (401 )           (401 )

Dividend Distribution

                                                    (1,943 )     (1,943 )

Net income

                                        15,104       15,104  

Balance at June 30, 2022

    70,125       (11,057 )   $ 7,013     $ 77,919     $     $ (44,635 )   $ 127,884     $ 168,181  


See notes to condensed consolidated financial statements.








Six Months Ended June 30,






(in thousands)




Net income

  $ 10,222     $ 27,268  

Adjustments to reconcile net income to net cash provided by operating activities:


Loss from discontinued operations, net of tax

    15       32  

Depreciation, depletion and amortization

    62,420       12,864  

Bargain purchase gain


Deferred taxes

    1,618       15,531  

Unrealized foreign exchange loss

    313       360  

Stock-based compensation

    1,254       2,264  

Cash settlements paid on exercised stock appreciation rights

    (233 )     (805 )

Derivative instruments (gain) loss, net

    (52 )     41,300  

Cash settlements paid on matured derivative contracts, net

    (63 )     (33,559 )

Cash settlements paid on asset retirement obligations

    (374 )      

Credit losses and other

    1,615       1,063  

Other operating loss, net

    62       5  

Operational expenses associated with equipment and other

    (1,196 )     718  

Change in operating assets and liabilities:


Trade receivables

    (5,208 )     (47,810 )

Accounts with joint venture owners

    21,746       10,283  

Other receivables

    (1,868 )     (943 )

Crude oil inventory

    (7,465 )     (12,274 )

Prepayments and other

    (69 )     1,570  

Value added tax and other receivables

    (2,302 )     (2,249 )

Other long-term assets

    1,508       (1,072 )

Accounts payable

    (10,897 )     (857 )

Foreign income taxes receivable/payable

    15,344       26,093  

Deferred tax liability

    (3,081 )      

Accrued liabilities and other

    (7,137 )     29,263  

Net cash provided by (used in) continuing operating activities

    77,584       69,045  

Net cash used in discontinued operating activities

    (15 )     (38 )

Net cash provided by (used in) operating activities

    77,569       69,007  



Property and equipment expenditures

    (54,832 )     (60,278 )

Net cash provided by (used in) continuing investing activities

    (54,832 )     (60,278 )

Net cash used in discontinued investing activities


Net cash provided by (used in) investing activities

    (54,832 )     (60,278 )



Proceeds from the issuances of common stock

    382       257  

Dividend distribution

    (13,452 )     (3,872 )

Treasury shares

    (11,403 )     (788 )

Deferred financing costs

    (30 )     (1,451 )

Payments of finance lease

    (3,379 )     (68 )

Net cash provided by (used in) in continuing financing activities

    (27,882 )     (5,922 )

Net cash used in discontinued financing activities


Net cash provided by (used in) in financing activities

    (27,882 )     (5,922 )

Effects of exchange rate changes on cash

    (285 )      


    (5,430 )     2,807  


    59,776       72,314  


  $ 54,346     $ 75,121  


See notes to condensed consolidated financial statements.








Six Months Ended June 30,






(in thousands)


Supplemental disclosure of cash flow information:


Interest paid, net of amounts capitalized

  $ 5,177     $ 113  

Supplemental disclosure of non-cash investing and financing activities:


Property and equipment additions incurred but not paid at end of period

  $ 26,746     $ 29,155  

Recognition of right-of-use finance lease assets and liabilities

  $ 3,273     $ 1,851  


See notes to condensed consolidated financial statements.









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 unaudited condensed consolidated financial statements (“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 per day 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. On June 5, 2023, OPEC meeting Saudi Arabia agreed to an additional 1 MMBbls per day for July 2023 but could be extended. In addition, members of OPEC+ agreed to extend the group's existing supply cuts of 3.7 MMBbls per day for another year ( December 2024). 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 June 30, 2023 was $78 per barrel. The average price for all 2022 and 2023 periods are summarized below:


Average Brent Prices






First Quarter

 $81.07  $100.87 

Second Quarter

 $77.99  $113.84 

Third Quarter

 $  $100.71 

Fourth Quarter

 $  $88.72 


During the year ended December 31, 2022 and continuing into 2023, the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel, services 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, any factors 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.




Principles of consolidation – The accompanying unaudited condensed consolidated 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 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 June 30, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”) and representing bank guarantees for customs clearance in Gabon. For Canada, approximately $0.1 million has been set aside as of June 30, 2023 related to property taxes reserved for Mountain View County. Long-term amounts at June 30, 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 June 30,






(in thousands)


Cash and cash equivalents

 $46,186  $53,062 

Restricted cash - current

  113   216 

Restricted cash - non-current

  1,779   1,752 

Abandonment funding

  6,268   20,091 

Total cash, cash equivalents and restricted cash

 $54,346  $75,121 


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 not 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 balance remained unchanged during the second quarter of 2023.


The Company is working on an updated abandonment study with Directorate of Hydrocarbons in Gabon and 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 required 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 June 30, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $19.7 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, and $19.7 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 228 MBbls of purchased crude oil from the supplier in the second half of 2022 and the first quarter of 2023. A $1.9 million payment was received in July for the receivable related to March deliveries.


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. At June 30, 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 establish third party cargoes to pay the back dated receivable as well as allow third party cargoes against current production


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 June 30, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $24.3 million ($15.8 million, net to VAALCO). As of June 30, 2023, the exchange rate was XAF 602.552 = $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. The Company is in discussions with the Ministry of Economy and Ministry of Hydrocarbon to obtain a suitable payment plan to address both the back dated VAT and the Government supplied refinery Sogara. VAALCO is in an advanced stage of negotiations for a payment plan resolving this. 


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 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 $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. During the three months ended June 30, 2023, there was no additional provision recorded.


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. An additional $0.2 million was transferred during the second quarter of 2023. As of  June 30, 2023, the Company has established a credit loss allowance for the full $0.5 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  June 30, 2023, the Company recognized an additional $0.5 million related to its Value added tax with Gabon. During the six months ended June 30, 2023, the Company recognized an additional $1.1 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.



Three Months Ended June 30,


Six Months Ended June 30,










(in thousands)


Allowance for credit losses and other


Balance at beginning of period

 $(12,832) $(6,135) $(8,704) $(5,741)

Credit loss charges and other, net of receipts

  (680)  (571)  (1,615)  (1,063)

Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023


Foreign currency gain (loss)

  (7)  317   (80)  415 

Balance at end of period

 $(13,519) $(6,389) $(13,519) $(6,389)


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, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. At June 30, 2023, the Company had 206,136 Bbls of crude oil underlift in Egypt. The Company resolved to sell domestically in the second quarter a proportion of its underlift from the second quarter to ensure an export cargo in August that has now been confirmed with terminal operator. Direct sales to Egypt were higher in the second quarter because of this but allows the Company to thrash out receivable settlements by way of offsets against sister EGPC companies that the Company has utilized in the drilling campaign. The export cargo in the third quarter will allow the Company to receive cash offshore and the Company is currently marketing this cargo with several traders.


Prepayments and Other – Included in “Prepayments and other” line item of the Company’s June 30, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $2.7 million of prepayments related to royalties in Gabon, $1.5 million in Gabon and corporate prepaid insurance, $4.0 million related to prepaid fuel in Egypt, $1.9 million in Egyptian advances to contractors, $0.4 million in prepaid Egypt payroll, and $5.1 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. The amount 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 five years for office and miscellaneous equipment and five to seven 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. To allocate the purchase price, the Company developed fair value models. 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 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 a cost 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 apply 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 based on 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 records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil in Gabon 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. 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 June 30, 2023


Balance Sheet Line


Level 1


Level 2


Level 3




(in thousands)




Derivative asset

Prepayments and other

 $  $158  $  $158 
   $  $158  $  $158 



SARs liability

Accrued liabilities and other

 $  $196  $  $196 
   $  $196  $  $196 




As of December 31, 2022


Balance Sheet Line


Level 1


Level 2


Level 3




(in thousands)




Derivative asset

Prepayments and other

 $  $102  $  $102 
   $  $102  $  $102 



SARs liability

Accrued liabilities and other

 $  $556  $  $556 
   $  $556  $  $556 


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 the Company'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 June 30, 2023 was 0.738 USD and 0.755, respectively.







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.


Not Yet Adopted


In  March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to debt contracts, receivables, leases, derivatives, and other contracts impacted by reference rate reform and other transactions affected by the cessation of the LIBOR. The expiration date of ASU 2020-04 was  December 31, 2022.


In  December 2022, the FASB issued ASU 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848,” to extend the expiration date of Topic 848 through  December 31, 2024. The expedients, if adopted, can be applied prospectively. As the Company implements alternative rates from LIBOR into the Company's current contracts, it is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.





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