~~☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~or

(~~Registrant’s~~Registrant’s telephone number, including area code)

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 ~~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. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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.

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 Rule 12b-2)~~Act). Yes ☐ No ☒

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)

VAALCO Energy, Inc. (together with its consolidated subsidiaries ~~“VAALCO,”~~“we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, ~~Texas based~~Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude ~~oil.~~oil, natural gas and natural gas liquids ("NGLs") properties. As operator, ~~we have~~the Company has production operations and ~~conduct development~~conducts exploration activities in Gabon ~~West Africa. As non-operator, we have~~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, ~~we have~~VAALCO has discontinued operations associated with ~~our~~ activities in Angola, West ~~Africa.~~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 ~~UK (North Sea), Ltd., VAALCO International, Inc., VAALCO~~ Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, ~~and~~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 ~~are unaudited, but in~~(“Financial Statements”) reflect the opinion of management ~~reflect~~and 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 ~~to be~~ 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 ~~our~~the Company’s Annual Report on Form ~~10-K~~10-K for the year ended December 31, ~~2016,~~ 2022, which ~~include~~includes a summary of the significant accounting policies.

~~Certain reclassifications have been made to prior period amounts related to reclassifying material and supplies to prepayments~~

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 ~~conform~~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 ~~period presentation. These reclassifications did~~ 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 ~~affect our consolidated financial results.~~ be collected.

The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.

Prepayments and Other – ~~Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is~~Included in ~~doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense~~“Prepayments and other” line item of the ~~condensed consolidated statements of operations.~~ The majority of our accounts receivable balances are with our joint venture partners and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to us. Portions of our costs in Gabon (including our VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). As of Company’s September 30, 2017, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF 20.5 billion (XAF 6.9 billion, net to VAALCO). As of September 30, 2017, the exchange rate was XAF~~555.742~~ ~~= $1.00.~~

In June 2016, we entered into an agreement with the government of Gabon to receive payments related to the outstanding VAT receivable balance, which was approximately XAF 16.3 billion (XAF 4.9 billion, net to VAALCO) as of December 31, 2015, in thirty-six monthly installments of $0.2 million, net to VAALCO. We received one monthly installment payment in July 2016; however, no further payments have been received. We are in discussions with the Gabonese government regarding the timing of the resumption of payments.

For the three and nine months ended September 30, 2017, we recorded allowances of $ (0.1) million and $0.2 million, respectively, related to VAT for which the government of Gabon has not reimbursed us. For the three and nine month periods ended September 30, 2016, we recorded allowances of $0.1 million and $0.6 million, respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the2023 condensed consolidated balance ~~sheets. Because both the VAT receivable~~sheet are $2.3 million of prepayments related to fixed assets, $4.3 million of prepayments related to royalties in Gabon, $1.0 million in Gabon and ~~the related allowances are denominated~~corporate prepaid insurance, $1.2 million in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on profit/loss. Such foreign currency gains (losses) are reported separatelyshort-term employees loans and advances to Gabon employees, $4.0 million in ~~the “Other, net” line item of the condensed consolidated statements of operations.~~

Nine Months Ended September 30,

2017

2016

(in thousands)
Allowance for bad debt

Balance at beginning of year

$
(5,211)

$
(4,221)
Charge to cost and expenses

(232)

(577)
Reclassification related to Sojitz acquisition

(694)

—
Foreign currency loss

(583)

(84)
Balance at end of period

$
(6,720)

$
(4,882)

Table of Contents

~~General and administrative related to shareholder matters~~ – General and administrative expenses related to shareholder matters for the three and nine months ended September 30, 2016 represent costs incurred related to shareholder litigation that was settled in April 2016. For 2016, the amounts also include the offsetting insurance proceeds related to these matters.

~~In May 2017,~~ ASU 2016-13 (“ASC 326”) on January 1, 2023 using the ~~Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope~~modified-retrospective approach. The modified-retrospective approach consists of Modification Accounting (ASU 2017-09) to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments in ASU 2017-09 are effective for all entities for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to an award modified on or after the adoption date. We are currently evaluating the provisions of ASU 2017-09 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01”). The purpose of the amendment is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities,applying the amendments in ASU 2017-01 are effective for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to acquisitions and disposals completed on or after the effective date, with no disclosures required at transition. The adoption of ASU 2017-01 is not expected to have a material impact on our ~~financial position, results of operations, cash flows and related disclosures~~.

~~In November~~ 2016 the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”), which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. We are currently evaluating the provisions of this guidance and are assessing its potential impact on our cash flows and related disclosures. Due to the nature of this accounting standards update, this may have an impact on items reported in our statements of cash flows, but no impact is expected on our financial position, results of operations or related disclosures as a result of implementation.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. We are currently evaluating the provisions of this guidance and are assessing its potential impact on our cash flows and related disclosures. Due to the nature of this accounting standards update, this may have an impact on items reported in our statements of cash flows, but no impact is expected on our financial position, results of operations or related disclosures as a result of implementation.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and partner receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date which is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model which increases the allowance when losses are probable. This change is effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with-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. ~~We are currently evaluating~~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.

On October 3, 2023 the Company adopted the provisions of ASU ~~2016-13~~ 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 and ~~are assessing its potential impact on our~~ ~~financial position, results~~ASU 2020-04, 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 ~~operations, cash flows~~the LIBOR. The adoption of these provisions changed the LIBOR rate interest rate component under the Company’s RBL Facility to a Secured Overnight Financing Rate (“SOFR”) plus margin and ~~related disclosures~~.

~~In February 2016,~~changed the ~~FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amends~~discount rate component under the ~~accounting standards for leases. ASU 2016-02 retains~~Company’s RBL Facility from a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar6 month LIBOR to a 6 month SOFR rate. Due to the ~~classification criteria~~provisions of ASU 2020-04 and 2023-06, the Company accounted for ~~distinguishing between capital leases and operating leases in~~ the ~~previous guidance. Certain aspects~~change as a modification of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliestdebt.

period presented using a modified retrospective approach. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. We are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period presented in the financial statements. Early adoption is allowed. Assuming adoption January 1, 2019, we expect that leases in effect on January 1, 2017 and leases entered into after such date will be reflected in accordance with the new standard in the audited consolidated financial statements included in our Annual Report on Form 10-K for 2019, including comparative financial statements presented in such report. We are in the preliminary stages of our gap assessment, but we expect that leases treated as operating leases with terms greater than 12 months will be capitalized. We expect adoption of this standard to result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This is expected to result in a material increase in total assets and liabilities as certain of our operating leases are significant as disclosed in our Annual Report on Form 10-K for 2016. We do not expect there will be a material overall impact on results of operations or cash flows. We are continuing to evaluate the impact of this new standard, and are in the process of developing our implementation plan.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The new standard will replace most existing revenue recognition guidance in U.S. GAAP. The core principle of ASU 2014-09 requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. In early 2016, the FASB issued additional guidance: ASU No. 2016-10, 2016-11 and 2016-12 (and together with ASU 2014-09, “Revenue Recognition ASU”). These updates provide further guidance and clarification on specific items within the previously issued ASU 2014-09. The Revenue Recognition ASU becomes effective for the Company as of January 1, 2018, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016, and allows for both retrospective and modified-retrospective methods of adoption. The Company does not plan to early adopt the standard. We have preliminarily concluded that we will adopt the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedients. We are substantially complete with our gap assessment and have determined that we will qualify for point in time recognition for essentially all of our sales. As such, the Company does not expect adoption of this standard to result in a change in the timing of revenue recognition compared to current practices, and therefore we do not expect adoption of this standard to have a material impact on our financial position or results of operations. Our contract review and documentation are substantially complete. We do expect that we will have expanded disclosures around the nature of our sales contracts and other matters related to revenues and the accounting for revenues. The remaining work to be completed in connection with the implementation of the standard is to develop the required disclosures and to evaluate and modify where necessary the internal controls and procedures related to revenue recognition.

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (ASU 2015-11) to simplify the measurement of inventory. This simplification applies to all inventory other than that measured using last-in, first out (“LIFO”) or the retail inventory method and requires measurement of inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. This guidance is to be applied prospectively effective for annual periods beginning after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. We adopted ASU 2015-11 in the first quarter of 2017 and the application of this guidance did not have a significant impact on our financial position, results of operations or cash flows.3. ACQUISITIONS AND DISPOSITIONS

~~On November 22, 2016, we closed on~~ In 2022 VAALCO completed the acquisition of TransGlobe during the fourth quarter. Subsequent to the acquisition, during the first quarter of 2023, a bargain purchase gain adjustment was recorded, impacting the deferred tax liability. At September 30, 2023, the purchase ~~of an additional 2.98% working interest (3.23% participating interest)~~accounting for the business combination has been completed. During the three months ended September 30, 2023 the deferred tax liability in Egypt did not change. During the ~~Etame Marin block located offshore~~nine months ended September 30, 2023, the ~~Republic~~deferred tax liability in Egypt was increased by $1.4 million, respectively, as of Gabon from Sojitz Etame Limited (“Sojitz”), which represents all interest owned by Sojitz in the concession. The acquisition had an effective date of August 1, 2016 and was funded with cash on hand.

The following amounts represent the preliminary estimates of the fair value of identifiable assets acquired and liabilities assumed in the Sojitz acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the acquisition.

~~All assets and liabilities associated with Sojitz’s interest~~ This resulted in Etame Marin block, including oil and gas properties, asset retirement obligations and working capital items were recorded at their fair value. In determining the fair value of the oil and gas properties, we prepared estimates of oil and natural gas reserves. We used estimated future prices to applya decrease to the ~~estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. The valuations to derive the~~bargain purchase price included the use of both proved and unproved categories of reserves, expectation for timing of production and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by management to calculate fair value of assets acquired and liabilities assumed. We may record purchase price adjustments as a result of changes in such estimates. These assumptions represent Level 3 inputs.

~~In April 2017, we completed the sale of our interests in the East Poplar Dome field in Montana for $0.3 million, resulting in a~~ gain of ~~approximately $0.3~~a corresponding $1.4 million ~~during~~for the nine months ended September 30, ~~2017.~~

~~Discontinued Operations - Angola~~ ~~In November 2006, our Angolan subsidiary,~~ ~~Vaalco Angola~~ (Kwanza), Inc., (“VAALCO Angola”), signed a production sharing contract for Block 5 offshore Angola (“PSA”). The four year primary term, referred to as the Initial Exploration Phase (IEP”), with an optional three year extension, awarded VAALCO Angola exploration rights to 1.4 million acres offshore central Angola, with a commitment to drill two exploratory wells. The IEP was extended on two occasions to run until December 1, 2014. In October 2014, VAALCO Angola entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required VAALCO Angola and the co-participating interest owner, the Angolan national oil company, Sonangol P&P, to drill two additional exploration wells. VAALCO Angola’s working interest is 40%2023, and it carries Sonangol P&P, for 10% of the work program. On September 30, 2016, VAALCO Angola notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, VAALCO Angola notified the national concessionaire, Sonangol E.P., that it was withdrawing from the PSA. Further to the decision to withdraw from Angola, VAALCO Angola has taken actions to begin reducing its officeis reflected in Angola and reducing future activities in Angola. As a result of this strategic shift, we classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in ourVAALCO's condensed consolidated statements of ~~operations. We segregated~~operations in the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in our condensed consolidated statements of cash flows. The following tables summarize selected financial information related to the Angola segment’s assets and liabilities as of September 30, 2017 and December 31, 2016 and its results of operations for the three and nine month periods ended September 30, 2017 and 2016.line, “Other expense, net.”

~~Under the PSA,~~ ~~Vaalco Angola~~and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during eachThe actual impact of the ~~exploration phases identified~~TransGlobe acquisition was an increase to “Crude oil, natural gas and NGLs sales” of $134.0 million and $21.0 million of “Net income” in the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each exploration well for which a drilling obligation remains under the terms of the PSA, of which VAALCO Angola’s participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2017 and December 31, 2016, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. However, we are currently engaged in discussions and meetings with newly appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid could be substantially less than the accrued amount.

The government-assigned working interest partner was delinquent in paying their share of the costs several times in 2009 and was removed from the production sharing contract in 2010 by a governmental decree. Efforts to collect from the defaulted partner were abandoned in 2012. The available 40% working interest in Block 5, offshore Angola was assigned to Sonangol P&P effective on January 1, 2014. We invoiced Sonangol P&P for the unpaid delinquent amounts from the defaulted partner plus the amounts incurred during the period prior to assignment of the working interest totaling $7.6 million plus interest in April 2014. Because this amount was not paid and Sonangol P&P was slow in paying monthly cash call invoices since their assignment, we placed Sonangol P&P in default in the first quarter of 2015.

On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery is reflected in the “Bad debt recovery and other” line item of our summarized results of discontinued operations for the nine months ended September

~~30, 2016. Default interest of $3.2 million is shown in the “Interest income” line item of our summarized results of discontinued operations for the nine months ended September 30, 2016.~~

We review our oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our 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 third quarter of 2017 that would cause us to believe the value of oil and natural gas producing properties should be impaired. Factors considered included the fact that we incurred no capital expenditures in 2017 related to the fields in the Etame Marin block, the future strip prices for the third quarter of 2017 increased, and there were no indicators that adjustments were needed to the year-end reserve report.

Declining forecasted oil prices and other factors caused us to perform impairment reviews of our proved properties in the first quarter of 2016 for all fields in the Etame Marin block offshore Gabon and the Hefley field in North Texas. However, no impairment was required for the quarter ended March 31, 2016. During the second quarter of 2016, forecasted oil prices improved significantly, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a well being shut-in in the Avouma field in the Etame Marine block offshore Gabon. After consider this factor, we determined that the undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the second quarter of 2016. During the third quarter of 2016, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a second well being shut-in in the Avouma field. After considering this factor, we determined that the undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the third quarter of 2016.

On June 29, 2016, we executed a Supplemental Agreement with the International Finance Corporation (the “IFC”) which, among other things, amended and restated our existing loan agreement to convert $20.0 million of the revolving portion of the credit facility, to a term loan (the “Term Loan”) with $15.0 million outstanding at that date. The amended loan agreement (“Amended Term Loan Agreement”) is ~~secured by the assets of our Gabon subsidiary,~~ VAALCO Gabon S.A. and is guaranteed by VAALCO as the parent company. The Amended Term Loan Agreement provides for quarterly principal and interest payments on the amounts currently outstanding through June 30, 2019, with interest accruing at a rate of LIBOR plus 5.75%.

The Amended Term Loan Agreement also provided for an additional $5.0 million, which could be requested in a single draw, subject to the IFC’s approval, through March 15, 2017. On March 14, 2017, we borrowed $4.2 million under this provision of the Amended Term Loan Agreement. The additional borrowings will be repaid in five quarterly principal installments commencing June 30, 2017, together with interest which will accrue at LIBOR plus 5.75%.

~~Compared to the $11.0 million principal carrying value of debt, net of deferred financing costs, as of September 30, 2017, the estimated fair value of the borrowings under the~~ ~~Amended Term Loan Agreement~~ is $11.2 million when measured using a discounted cash flow model over the life of the current borrowings at forecasted interest rates. The inputs to this model are Level 3 in the fair value hierarchy.

~~Under the~~ ~~Amended Term Loan Agreement, the ratio of quarter-end net debt to EBITDAX (as defined in the~~ ~~Amended Term Loan Agreement) must be no more than 3.0 to 1.0.~~ Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at each semi-annual review period. Certain of VAALCO’s subsidiaries are contractually prohibited from making payments, loans or transferring assets to VAALCO or other affiliated entities. Specifically, under the Amended Term Loan Agreement, VAALCO Gabon S.A. could be restricted from transferring assets or making dividends, if the positive and negative covenants are not in compliance with the Amended Term Loan Agreement. Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain; therefore, we can make no assurance that we will be able to comply with our Amended Term Loan Agreement covenants in future periods. Factors that could impact our quarter-end financial covenants in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. We were in compliance with all financial covenants as of September 30, 2017 and December 31, 2016.

Until June 29, 2016, under the terms of the original revolving credit facility, we paid commitment fees on the undrawn portion of the total commitment. Commitment fees had been equal to 1.5% of the unused balance of a senior tranche of $50.0 million and 2.3% of the unused balance of a subordinated tranche of $15.0 million when a commitment was available for utilization. With the execution of the Supplemental Agreement with the IFC in June 2016, beginning June 29, 2016 and continuing through March 14, 2017, commitment fees were equal to 2.3% of the undrawn Term Loan amount of $5.0 million. There are no further commitment fees owing after March 14, 2017.

We capitalize interest and commitment fees related to expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use.

~~The table below shows the components of the “Interest expense, net” line item of our~~ condensed consolidated statements of operations and comprehensive income for the ~~average effective interest rate, excluding commitment fees,~~nine months ended September 30, 2023. The impact for the three months ended September 30, 2023 was an increase to “Crude oil, natural gas and NGLs sales” of $59.0 million and $19.3 million of “Net Income” in the condensed consolidated statements of operations and comprehensive income.

The unaudited pro forma results presented below have been prepared to give the effect of the TransGlobe acquisition discussed above on ~~our borrowings:~~the Company’s results for the three and nine months ended September 30,2022, as if the acquisition 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 acquisition had been completed on such date or project the Company’s results of operations for any future date or period.

The Company’s operations are based in Gabon, Egypt, and Canada, and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s 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 and nine months ended September 30, 2023 and 2022 as well as long-lived assets and segment assets at September 30, 2023 and December 31, 2022 are as follows:

For the three and nine months ended September 30, 2023 sales of crude oil to Glencore made up 100% of Etame revenues. For the three and nine months ended September 30, 2022, sales of crude oil to ExxonMobil Sales and Supply LLC made up 100% of Etame revenues through July 2022. For August and September 2022, sales to Glencore made up 100% of Etame revenues. For the three months ended September 30, 2023, the EGPC and Mercuria split the Company's crude oil sales in Egypt. For the nine months ended September 30, 2023, Mercuria covered 100% of the Company’s crude oil sales in Egypt in the first quarter; the EGPC covered 100% of sales in the second quarter; and, sales were split between Mercuria and the EGPC in the third quarter. For the three and nine months ended September 30, 2023, revenues in Canada were concentrated in three separate customers. For the nine months ended September 30, 2023, these customers were Plains Midstream (41.9%), AltaGas (18.4%), and PetroGas Energy (28.4%). For the three months ended September 30, 2023, these customers were PetroGas Energy (51.0%), Plains Midstream (19.8%) and AltaGas (17.5%). Concentrations of accounts receivable are similar to the revenue percentages.

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:

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 following table presents revenues from contracts with customers as well as revenues associated with the obligations under the Etame PSC.

With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations 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 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 $29.2 million foreign income tax payable as of September 30, 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.

The Company’s crude oil, natural gas and NGLs properties and equipment is comprised of the following:

The East Arta 54 appraisal well in Egypt was abandoned during the period and subsequently expensed to Exploration Expense. The impact resulted in $1.2 million of expense during the three and nine months ended September 30, 2023.

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 September 30, 2023:

The following table sets forth the loss on derivative instruments on the Company’s unaudited condensed consolidated statements of operations and comprehensive income:

Under the terms of ~~securing the first of two five-year extensions to~~ the Etame ~~field production license to which we are entitled from~~PSC, the ~~government of Gabon, we agreed to~~Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. ~~The agreement was finalized in~~At September 30, 2023, the ~~first quarter of 2014 (effective as of 2011) providing for annual funding over a period of ten years in amounts equal to 12.14%~~balance of the ~~total~~ abandonment estimate for the first seven years and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable. The abandonment estimate used for this purpose is approximately ~~$61.1~~fund was $10.7 million ($~~19.0~~6.3 million, net to VAALCO) on an undiscounted basis. ~~Through September 30, 2017, $27.4 million ($8.5 million net to VAALCO)~~The annual payments will be adjusted based on ~~an undiscounted basis has been funded.~~revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” asin the “Abandonment funding” ~~on our~~line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change ~~our~~the asset retirement obligation and the amount of future abandonment funding payments.

~~We are subject to periodic routine audits by various government agencies~~In the first quarter of 2023, the Directorate of Hydrocarbons 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.~~

In 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded to the audit findings in January 2017. Since providing our response, there have been changes in the Gabonese officials responsible for the audit. We are currently working with the newly appointed representatives to resolve the audit findings. We do not anticipate that the ultimate outcome of this audit will haveapproved a ~~material effect on our financial condition, results of operations or liquidity.~~

~~As of December 31, 2016, we had accrued $1.0~~$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. No activity was noted in the abandonment funding account during the second or third quarter of 2023.

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 two one-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, the Company 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 the Company). 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 settle on the Company’s restricted cash balances associated with the FPSO. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in ~~“Accrued~~decommissioning fees, which was reported as a separate line item on the income statement. No additional expense was incurred beyond the initial expense.

During the second quarter of 2023, the Joint Operating Group ("VAALCO, Addax, PetroEnergy and Tullow") were informed by BW Offshore the supplier of the former FPSO that waste disposal of naturally occurring radioactive material was present in the final volumes and tanks on the vessel as is typical. The Joint Operating Group have an obligation to lift and properly dispose of this waste. The Company has provided for an accrual for the collection and disposal of the waste via tank cleaning activities that began in September and will continue in October 2023. The cost is expected to be around $9.6 million gross ($5.6 million net to VAALCO).

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 a maximum period of 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. Effective August 16, 2023, there was an amendment to the share repurchase plan allowing VAALCO to repurchase up to $2 million a month through November 2023, but this did not change the total repurchase amount of $30 million.

The following table shows the repurchases of equity securities related to the share repurchase program from July 1, 2023 through September 30, 2023:

The following table shows the repurchases of equity securities related to the share repurchase program after September 30, 2023 throughNovember 3, 2023:

The actual timing, number and value of shares repurchased under the share buyback program will depend on several 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.

On January 20, 2022, prior to the consummation of the acquisition, 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 condition's 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 $10.0 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 ~~and other” on our~~of $27.1 million at September 30, 2023. On the unaudited condensed consolidated balance sheet, for certain payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor. While the payroll taxes were for individuals who were not our employees, we could be deemed liable for these expenses as the end user$9.7 million of the ~~services provided. These~~modernization payment liability was recorded in the line item "Accrued liabilities ~~were substantially resolved at~~and other" and $17.4 million was recorded in "Other long-term liabilities".

The Company also has minimum financial work commitments of $50.0 million per each five-year period of the ~~accrued amount in January 2017.~~

At 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 September 30, ~~2017, we had accrued $1.0~~2023, all investments have exceeded the five-year minimum $50 million ~~net~~threshold and any excess carries forward to ~~VAALCO~~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 ~~“Accrued liabilities~~the historic commercial terms and ~~other”~~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 ~~our~~historical realized prices. However, the cumulative value to be received because 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 September 30, 2023, the remaining $50.3 million of the original $67.5 million receivable is recorded on the unaudited condensed consolidated balance sheet ~~for potential fees which may result from certain regulatory audits.~~in Receivables-Other, net.

In 2014, we entered into a long-term contract for the Constellation II drilling rig that was under a long-term contract for the multi-well development drilling campaign offshore Gabon. The campaign included the drilling of development wells and workovers of existingGovernment Related Receivables

~~wells~~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 procure and deliver to Sogara refinery an amount of oil equal to its proportionate share of crude oil to meet the domestic market need in offset of its domestic market obligation in the Etame ~~Marin block.~~ ~~We began demobilization in January 2016~~PSC. In exchange, the Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered.

In November 2022, a receivable from Sogara became past due and ~~released~~ the ~~drilling rig in February 2016, prior~~Company has not received payments. At September 30, 2023, the amount due to the ~~original July 2016 contract termination date, because we no longer intended to drill any wells~~Company from the refinery is $17.9 million. A separate credit loss of $3.5 million has been provided for. The Company is in ~~2016 on our Etame Marin block offshore Gabon.~~ ~~In June 2016, we reached an agreement~~ongoing discussions with the ~~drilling contractor~~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 vast majority owed to it for ~~us to pay $5.1 million net to VAALCO’s interest for unused rig days~~both the VAT receivable and receivable under the ~~contract. We paid this amount, plus~~oil supply arrangement, but the ~~demobilization charges, in seven equal monthly installments, which began in July 2016 and ended in January 2017.~~ ~~The related expense was reported in the “Other operating expense” line item in our condensed consolidated statement~~terms of ~~operations for the three and nine months ended September 30, 2016.~~recovery have not fully been finalized.

During 2016, we executed crude oil put contracts as market conditions allowed in order to economically hedge anticipated 2016 and 2017 cash flows from crude oil producing activities. While these crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in oil prices, we have not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. These changes in fair value have no cash flow impact. The impact to cash flow occurs upon settlement of the underlying contract. We do not enter into derivative instruments for speculative or trading proposes.Lease Obligations

As of September 30, 2017, we had unexpired oil puts covering 180,000 barrels of anticipated sales volumes for the period from October 2017 through December 31, 2017 at a weighted average price of $50.00. Our put contracts are subject to agreements similar to a master netting agreement, under which we have the legal right to offset assets and liabilities. At September 30, 2017, our unexpired oil puts represented a fair value asset position of $0.1 million in the “Prepayments and other” line item of our condensed consolidated balance sheets.

The following table ~~sets forth, by level within~~describes the ~~fair value hierarchy and location on our condensed consolidated balance sheets,~~future maturities of the ~~reported values~~Company’s lease liabilities at September 30, 2023:

Under the joint operating agreements, other joint venture owners are obligated to fund $49.6 million of ~~derivative instruments accounted for at fair value on a recurring basis:~~the $120.3 million in future lease liabilities.

Carrying

Fair Value Measurements Using
Derivative Item

Balance Sheet Line

Value

Level 1

Level 2

Level 3

(in thousands)
Crude oil puts

Prepayments and other

Balance at September 30, 2017

$
61

$
—

$
61

$
—
Balance at December 31, 2016

$
1,227

$
—

$
1,227

$
—

As of September 30, 2023 and December 31, 2022, the ~~Black’s option pricing model. Level 2 observable inputs used~~Company had no outstanding debt.

On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the ~~valuation model include market information as~~term of the ~~reporting date, such~~Facility, the Initial Total Commitment, as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the put contract fair value includes the impact of the counterparty’s non-performance risk.

~~To mitigate counterparty risk, we enter into such derivative contracts with creditworthy financial institutions deemed~~increased by ~~management as competent and competitive market makers.~~

~~The following table sets forth the loss on derivative instruments in our condensed consolidated statements of operations:~~

Our stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of our Board of Directors to issue various types of incentive compensation. Currently, we have issued stock options, restricted shares and SARs under the 2014 Long-Term Incentive Plan (“2014 Plan”). At September 30, 2017, 2,126,942 shares were authorized for future grants under this plan.

For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Planany Additional Commitment, will be reduced by ~~twice~~ $6.3 million. On October 1, 2023, the ~~number~~amount available to be drawn under the facility was $43.8 million.

The Facility provides for determination of ~~restricted shares. We have~~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 originally bore an 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). On October 3, 2023 the Company signed an Amended and Restated Facility Agreement to replace the LIBOR component, in the original Facility Agreement, with a SOFR plus credit adjustment spread rate. The SOFR plus credit adjustment spread rate is intended to approximate the LIBOR component in the original Facility Agreement and the LIBOR component was replaced due to LIBOR being discontinued as a global reference rate.

Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.

The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million at any time. As of September 30, 2023, the Company's borrowing base was $50.0 million. The amount the Company can borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. Regarding the requirement, the Company must deliver its annual financial statements to Glencore within 90 days of the end of each fiscal year. The Company delivered the annual financial statements, along with its covenant compliance certificate to Glencore on April 11, 2023. At September 30, 2023, the Company was in compliance with all other debt covenants and had no ~~set policy for sourcing shares for option grants. Historically~~outstanding borrowings under the ~~shares issued under option grants~~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 ~~new shares.~~satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).

~~We record non-cash compensation expense related to stock-based compensation as general~~

In connection with the TransGlobe acquisition in October 2022, and ~~administrative expense. For the three months ended September 30, 2017 and 2016, non-cash compensation expense was $0.2 million and $(1.3) million, respectively, related~~prior to the ~~issuance~~effective time of ~~stock options~~the acquisition, TransGlobe repaid in full all outstanding obligations and ~~restricted stock. For~~ liabilities owed under TransGlobe’s credit facility with ATB Financial (the "ATB Facility"), representing approximately Canadian $4.1 million. On January 5, 2023, the ~~nine months ended September 30, 2017 and 2016, non-cash compensation~~ATB Facility was ~~$0.9~~formally closed. Termination of the ATB Facility will not affect the Company's $50.0 million $0.1 million, respectively, related to the issuance of stock options and restricted stock. Because we do not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.senior secured reserve-based revolving credit facility with Glencore.

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 ~~our Board~~the Company’s board of ~~Directors, which in the past has been~~directors that is generally a five year life, with the options vesting over a service period of up to five years. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. There were immaterial cash proceeds from the exercise of stock options in the three ~~and nine months ended September 30, 2017 and 2016. For the nine months ended September 30, 2017, options for 1,550,442 shares were granted to employees; these options vest over a three-year~~-year period, vesting in three equal parts on the ~~first, second and third~~ anniversaries ~~after~~from the date of ~~grant. Options~~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.

In June 2023, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 334,753 shares at an exercise price of $4.19 per share and a life of ten years. For each performance stock option award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $4.82 per share; performance stock options with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $5.54 per share; and performance stock options with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $6.37 per share. These awards are option awards that contain a market condition. Compensation cost for ~~465,950 shares were granted~~such awards is recognized ratably over the derived service period and compensation cost related to ~~our non-employee directors, which were fully vested upon their grant.~~awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.

During the nine months ended September 30, ~~2017 is provided below:~~ 2023 and 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.

Restricted stock granted to employees will vest over a period determined by the Compensation Committee ~~which~~that is generally a three ~~year~~-year period, vesting in three equal parts on the ~~first three~~ anniversaries offollowing the date of the grant. ~~Share grants~~Restricted stock granted to directors will vest ~~immediately and are not restricted. The following is a summary~~on the earlier of ~~activity in unvested restricted stock in~~(i) the ~~nine months ended September 30, 2017.~~

~~In both the three months ended September 30, 2017 and 2016, 9,117 shares were added to treasury due to tax withholding as a result~~first anniversary of the vesting of restricted shares. In the nine months ended September 30, 2017 and 2016, 9,117 shares and 40,926 shares, respectively, were added to treasury due to tax withholding as a result of the vesting of restricted shares.

SARs are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR price per share specified in a SAR award on the date of grant ~~(which may not be less than~~and (ii) the ~~fair market value~~first annual meeting of ~~our common stock on~~stockholders following the date of ~~grant) and the fair market value per share on~~grant (but not less than fifty (50) weeks following the date of ~~exercise~~grant). The vesting of the ~~SAR. SARs granted to participants will become exercisable over a period determined by~~restricted stock is dependent upon, among other things, the ~~Compensation Committee of our Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by~~employees’ and directors’ continued service with the ~~Compensation Committee of our Board of Directors.~~Company.

During the nine months ended September 30, ~~2017, 1,049,528 SARs~~2023 796,639 restricted shared were granted, ~~all having an exercise price~~354,080 shares vested, and 22,325 shares were forfeited. As of $1.20 per share. One-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds $1.30; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds $1.50; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds $1.75. SARs granted in 2016 vest over a three year period with a life of 5 years; these SARs have a maximum spread equal to 300% of the $1.04 SAR price per share specified in a SAR award on the date of grant. The amounts of compensation payable related to these awards through September 30, ~~2017 have not been significant.~~2023, 1,084,671 restricted shares were unvested and outstanding.

~~SAR activity for the nine months ended September 30, 2017 is provided below:~~13. INCOME TAXES

VAALCO and its domestic subsidiaries file a consolidated ~~United States~~U.S. income tax return. Certain ~~subsidiaries’ operations are~~foreign subsidiaries also ~~subject to~~file tax returns in their respective local jurisdictions that include Canada, Egypt, Equatorial Guinea and Gabon.

As discussed further in the Notes to the consolidated financial statements in our Form 10-K for December 31, 2016, we have deferred tax assets related to foreign tax credits, alternative minimum tax credits, and domestic and foreign net operating losses (“NOLs”). Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. We do not anticipate utilization of the foreign tax credits prior to expiration nor do we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, full valuation allowances have been recorded as of September 30, 2017 and December 31, 2016.

~~Income~~ taxes ~~attributable to continuing operations for the three and nine months ended September 30, 2017 and 2016~~payable are attributable to ~~foreign~~Gabon and Egypt for the nine months ended September 30, 2023 and 2022 in addition to domestic income taxes ~~payable~~ in ~~Gabon.~~

~~In April 2017, we were notified by~~ the U.S. ~~Internal Revenue Service (“IRS”)~~

Provision for income taxes related to income from continuing operations consists of the following:

The Company’s effective tax rate for the three and nine months ended September 30, 2023, excluding the impact of discrete items, was 63.85% and 63.57%. For the three and nine months ended September 30, 2022, the effective tax rates were 131.4% and 90.3%. The total tax expense for the three months ended September 30, 2023, includes a discrete amount of $5.4 million primarily related to adjustments made because of changes to oil price (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, i.e., oil price adjustment). For the nine months ended September 30, 2023, the current tax expense of $51.5 million includes a $8.0 million unfavorable oil price adjustment. After excluding that ~~they would be conducting~~impact, current income taxes were an ~~audit~~expense of ~~our 2014 U.S. federal tax return. The audit is in progress; however, to date,~~$43.5 million for the ~~IRS has not communicated any findings.~~

~~Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each~~ period. For the ~~calculation~~three months ended September 30,2022, the current tax benefit of ~~diluted shares, we assume that restricted stock~~$1.2 million includes an $8.7 million favorable 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 this impact, current income taxes were $7.5 million for the period. For the nine months ended September 30, 2022, the current tax expense of $24.9 million includes a $4.4 million favorable 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 $29.3 million for the period.

As of September 30, 2023, the Company had no material uncertain tax positions. The Company’s policy is ~~outstanding on the date~~to recognize potential interest and penalties related to unrecognized tax benefits as a component of ~~vesting, and we assume the issuance of shares from~~ ~~the exercise of stock options using the treasury stock method.~~

~~Our operations are based in Gabon, Equatorial Guinea and the U.S.~~ ~~Each of our three reportable operating segments is organized and managed based upon geographic location. Our Chief Executive Officer, who~~TransGlobe Energy's Canadian segment is the ~~chief operating decision maker, and management,~~ ~~review and evaluate~~Canadian Dollar. All of the ~~operation~~Company’s other comprehensive income arises from the currency translation of ~~each geographic~~TransGlobe Energy Canadian segment ~~separately primarily based on Operating~~to USD.

The components of accumulated other comprehensive 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 which are not allocated to the reportable operating segments.~~

~~Segment activity of continuing operations for the three and nine months ended September 30, 2017 and 2016 and segment assets at September 30, 2017 and December 31, 2016~~ are as follows:

Three Months Ended September 30, 2017
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
18,162

$
—

$
16

$
—

$
18,178
Depreciation, depletion and amortization

1,633

—

—

67

1,700
Bad debt expense and other

(49)

—

—

—

(49)
Operating income (loss)

6,067

(44)

10

(2,312)

3,721
Interest expense, net

(327)

—

—

—

(327)
Income tax expense

2,749

—

—

—

2,749
Additions to property and equipment - accrual

237

—

—

60

297

Three Months Ended September 30, 2016
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
14,540

$
—

$
95

$
—

$
14,635
Depreciation, depletion and amortization

1,508

—

38

61

1,607
Impairment of proved properties

—

—

88

—

88
Bad debt expense and other

63

—

—

—

63
Other operating expense

324

—

—

—

324
Operating income (loss)

5,013

(184)

(61)

(1,078)

3,690
Interest income (expense), net

(329)

—

—

2

(327)
Income tax expense (benefit)

2,305

—

—

(107)

2,198
Additions to property and equipment - accrual

674

—

—

7

681

Nine Months Ended September 30, 2017
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
59,823

$
—

$
46

$
—

$
59,869
Depreciation, depletion and amortization

5,344

—

1

194

5,539
Bad debt expense and other

232

—

—

—

232
Operating income (loss)

25,117

(97)

356

(7,920)

17,456
Interest expense, net

(1,108)

—

—

—

(1,108)
Income tax expense

9,039

—

—

—

9,039
Additions to property and equipment - accrual

1,051

—

—

60

1,111

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Nine Months Ended September 30, 2016
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
44,212

$
—

$
246

$
-

$
44,458
Depreciation, depletion and amortization

5,484

—

121

182

5,787
Impairment of proved properties

—

—

88

—

88
Bad debt expense and other

577

—

—

—

577
Other operating expense

9,959

—

—

—

9,959
Operating income (loss)

1,481

(319)

(64)

(6,308)

(5,210)
Interest expense, net

(2,285)

—

—

—

(2,285)
Income tax expense

6,884

—

—

—

6,884
Additions to property and equipment - accrual

(1,819)

—

140

7

(1,672)

(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Total assets from continuing operations:

As of September 30, 2017

$
61,694

$
10,093

$
83

$
1,892

$
73,762
As of December 31, 2016

64,478

10,122

382

3,911

78,893

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ITEM 2. ~~MANAGEMENT’S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~SPECIAL NOTE~~

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This ~~report~~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 ~~report~~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”,~~ “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:

●

volatility of, and declines and weaknesses in crude oil, ~~and~~ natural gas ~~prices;~~and NGLs prices, as well as our ability to offset volatility in prices through the use of hedging transactions;

●

our ability to ~~maintain sufficient liquidity in order to fully implement~~remediate our ~~business plan;~~material weaknesses;

●

·the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves;

●

impairments in the value of our crude oil, natural gas and NGLs assets;

●

future capital requirements;

●

our ability to ~~meet the financial covenants of~~maintain sufficient liquidity in order to fully implement our ~~Amended Term Loan Agreement;~~business plan;

our ability to resolve satisfactorily matters related to our exit from Angola, including our obligations to pay the amount, as it is ultimately determined, of our liabilities to Sonangol E.P. with respect to our production sharing contract;

~~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;~~

●

our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash ~~requirements through December 31, 2018;~~requirements;

●

·the ability of the BWE Consortium to successfully execute its business plan;

●

our ability to ~~meet the continued listing standards of the New York Stock Exchange (“NYSE”),~~attract capital or ~~to cure any deficiency in meeting the listing standards;~~obtain debt financing arrangements;

~~our ability to replace our Amended Term Loan Agreement facility with another credit facility to help fund our future capital requirements;~~

~~unanticipated issues and liabilities arising from non-compliance with environmental regulations;~~

~~the uncertainty of estimates of oil and natural gas reserves;~~

~~the impact of competition;~~

~~the availability and cost of seismic, drilling and other equipment;~~

~~operating hazards inherent in the exploration for and production of oil and natural gas;~~

~~difficulties encountered during the exploration for and production of oil and natural gas;~~

~~difficulties encountered in measuring, transporting and delivering oil to commercial markets;~~

~~the discovery, acquisition, development and replacement of oil and natural gas reserves;~~

~~timing and amount of future production of oil and natural gas;~~

~~hedging decisions, including whether or not to enter into derivative financial instruments;~~

~~our ability to effectively integrate assets and properties that we acquire into our operations;~~

●

our ability to pay the expenditures required in order to develop certain of our ~~properties offshore Equatorial Guinea;~~properties;

●

·operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs;

●

difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs;

●

the impact of competition;

●

our ability to identify and complete complementary opportunistic acquisitions;

●

our ability to effectively integrate assets and properties that we acquire into our operations;

●

weather conditions;

●

the uncertainty of estimates of crude oil, natural gas and NGLs reserves;

●

currency exchange rates and regulations;

●

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);
	●	the availability and cost of seismic, drilling and other equipment;

●

difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets;

●

timing and amount of future production of crude oil, natural gas and NGLs;

●

hedging decisions, including whether or not to enter into derivative financial instruments;

●

general economic conditions, including any future economic downturn, the impact of inflation, and disruption in financial ~~markets and the availability of~~ credit;

●

~~changes in customer demand and producers’ supply;~~

~~future capital requirements and~~ our ability to ~~attract capital;~~enter into new customer contracts;

●

·changes in customer demand and producers’ supply;

~~currency exchange rates;~~

●

actions by the governments of and other significant actors with respect to events occurring in the countries in ~~the countries in~~ which we operate;

●

actions by our joint venture ~~partners;~~owners;

●

·compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;

~~compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;~~

●

the outcome of any governmental audit; and

●

actions of operators of our crude oil, ~~and~~ natural gas ~~properties;~~and NGLs properties.

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~~the timing and effectiveness of our remediating the significant deficiencies and material weaknesses in our internal control over financial reporting; and~~

~~weather conditions.~~

The information contained in this ~~report~~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, ~~2016~~2022 (“~~2016~~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 ~~which~~that are included in this ~~report~~Quarterly Report and the ~~2016~~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 ~~report.~~Quarterly Report.

Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this ~~“Special Note~~“Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude ~~oil.~~oil, natural gas and NGLs. As operator, we have production operations and conduct ~~development~~exploration activities in Gabon, West ~~Africa.~~Africa, Egypt and Canada. We also have opportunities to participate in development and exploration activities ~~as a non-operator~~ in Equatorial Guinea, West Africa. ~~As discussed further in Note 3 to the condensed consolidated financial statements, we~~We have discontinued operations associated with our activities in Angola, West Africa and Yemen.

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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 ~~April 2017 we~~the first quarter of 2023. Dividends Payments were made during the first three quarters of 2023 in accordance with this policy change. On November 7, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on December 21, 2023 to stockholders of record at the close of business on November 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.

Amendment to Facility Agreement

On October 3, 2023, VAALCO Gabon (Etame), Inc. (the “Borrower”), a wholly owned subsidiary of the Company, entered into an amended and restated facility agreement that amends and restates the Facility Agreement dated May 16, 2022, by and among the Company, VAALCO Gabon, SA, Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent, the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein. The Initial Credit Facility made use of the London Inter-Bank Offered Rate (“LIBOR”) to calculate the interest rate applicable to borrowings thereunder. As a result of the recent discontinuation of LIBOR as a published interest rate, the new facility amends the Initial Credit Facility to instead make use of the Secured Overnight Financing Rate to calculate the interest rate applicable to borrowings thereunder. As of October 1, 2023, the amount available to be drawn under the facility was $43.8 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 ~~sale~~fourth quarter of ~~our interests~~2022. We are currently evaluating locations and planning for the next drilling campaign at Etame that is expected to occur in ~~Montana.~~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 and improved operational performance. The Company will continue to focus on operational excellence, including production uptime and enhancement in 2023 to minimize decline until the next drilling campaign.

~~A significant component~~

At the end of ~~our results~~September 2023, all wells were online from the end of ~~operations is dependent upon~~2022 as the ~~difference between prices received for our offshore Gabon oil~~gas lift compression system was successfully commissioned. This gas lift compression system increased the production and the ~~costs~~reliability of two subsea wells, positively impacting our volumes for the nine months ended September 30, 2023. Gas lift compression and subsea wells remained online with a high level of reliability through the nine months ended September 30, 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 ~~find~~the FSO. Since the field reconfiguration in 2022, a better understanding of the field’s operating parameters, through the new central processing facility (CPF) on Etame, has resulted in a more efficient and ~~produce such oil. Oil~~cost effective flow assurance program. Continued optimization and ~~natural gas prices~~understanding of the post reconfiguration process dynamics of the Etame platform, have ~~been volatile~~maintained a very high uptime availability of Etame Facility and ~~subject~~in turn the complete Etame field during the second quarter. Combining this with individual well and facility chemical injection optimization and facility pipeline pigging adjustments both on frequency of pigging and flow path targeting, has increased production through decrease in pipeline internal buildup and resulting drop in pipeline back pressure, this in turn has provided more stable operations resulting in lower downtime. Through the third quarter of 2023, this continues to ~~fluctuations based~~be a focus with positive results in production rates and uptime.

Preventative maintenance activities remained at levels prior to the field reconfiguration, as the focus was on ~~a number~~steady state operation following project completion. Equipment reliability and availability remain at high levels. The actual percentages of ~~factors beyond our control. Beginning~~Corrective Maintenance performed versus Preventative Maintenance performed remain well within VAALCO and Industry Best Practice standards. Major planned maintenance was carried out on Etame Power generation turbines.

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Egypt

We continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed six wells in the third quarter of ~~2014,~~2023, five development wells K-80, K-84, K-85, M-24, Arta-91 and one deep appraisal well EA-54. Drilling continues on the ~~global prices for oil~~EA-55 development well in the fourth quarter which will be the last well of the 2023 campaign. We continue to drill an average of 2 wells per month with the EDC-64 rig and ~~natural gas began~~we have drilled 18 wells this year as well as completed the Arta-77Hz at the beginning of 2023. The 2023 firm and contingent work program was drilled more efficiently and came in under budget.

A summary of the Egyptian drilling campaign's impact during the third quarter is presented below:

VAALCO Egypt Q3 Wells
Well	Spud date	Pay	Zones	Completion	Interval	IP-30 Rate BOPD
K-80	7/1/2023	141.4 feet	Asl-A, B, D and E	Asl-E	16.4 feet	144
K-84	7/16/2023	98.8 feet	Asl- D, E, F and G	Asl-G	19.7 feet	158
K-85	7/31/2023	63.3 feet	Asl- D, E, F and G	Asl-E	9.8 feet	164
M-24	8/14/2023	70.2 feet	Asl-A, B and D	Asl-D	9.8 feet	120
Arta-91	9/1/2023	40 feet	Red-bed/Nukhl	Red-bed	20.0 feet	94
EA-54	9/12/2023	none	Red-bed/Nukhl	Abandoned	none	none

Canada

Early in 2023, two wells, the 04-10-29-03W5 and the 04-19-29-3W5, were tied in. Both wells are now online and producing.

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The 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5, spudded on January 28, 2023. The well was drilled to a ~~dramatic decline which continued through 2015~~total depth of 22,024 feet. The second well of the program, 16-30-29-3W5, was spudded on February 22, 2023, and ~~into 2016. During this period, we scaled back our global operations, divested non-core assets, amended our credit agreement~~drilled to a total depth of 14,446 feet. The 2 wells were completed between late March and ~~focused on reducing costs~~early April and ~~maximizing our cash flows. Current prices, while higher than those~~tied in and equipped in April and early May. 12-12-30-4W5 was put online in late April, and 16-30-29-3W5 was put online in early ~~2016, are~~May with cycle times that were significantly less than ~~they were~~historical cycle times. The wells flowed in the ~~several years prior~~months of May and June. In early July the pump and rods were run on both wells. Both wells continue to ~~mid-2014. A decline in oil~~produce and ~~natural gas prices and a sustained period of oil and natural gas prices at depressed levels could have a material adverse effect on our financial condition.~~

~~CURRENT DEVELOPMENTS~~

~~During 2016, the global oil supply~~both wells continued to ~~outpace demand, having a dampening effect on the recovery of realized crude oil prices. While global oil supply and demand were closer to being balanced~~exceed expectations during the ~~first nine months~~third quarter of 2017, no assurances can be made that this trend will continue. Prices for crude oil improved during the second half of 2016 (ICE Dated Brent crude oil prices increased from approximately $36 per Bbl in early January 2016 to approximately $55 per Bbl at the end of 2016, and fluctuated between $44 and $61 per Bbl from January 2017 through October 2017).2023.

On June 29, 2016, we executed a Supplemental Agreement with the International Finance Corporation (the “IFC”), the lender under our revolving credit facility which among other things, amended and restated our loan agreement to convert $20.0 million of the revolving portion of the credit facility into a term loan with $15.0 million outstanding at that date. The amended loan agreement also provided us with an option to borrow an additional $5.0 million in a single draw, subject to IFC approval, through March 15, 2017. On March 14, 2017, we borrowed $4.2 million under the provisions of the Amended Term Loan Agreement. Currently under this loan agreement, we have $11.0 million in total debt, net of deferred financing costs, outstanding. See Note 5 to the condensed consolidated financial statements and “Capital Resources and Liquidity—Liquidity—Credit Facility” below for additional details about the loan agreement. There is no further ability to borrow additional sums under our IFC credit facility.

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Our common stock is listed and traded on the NYSE. On April 6 and June 28, 2017, we received notices from the NYSE that we were not in compliance with a provision of the NYSE’s continued listing standards that require the average closing price of our common stock to be at least $1.00 per share over a consecutive 30-trading-day period. The 30 trading-day average closing price of the Company’s common stock for these notices had been $0.99 per share. We have responded to these notifications, and will have six months from our receipt of the June 28, 2017 notice (which may be extended to our next annual shareholder meeting) to regain compliance with the minimum share price rule. This notice from the NYSE does not affect our business operations or trigger any default or other violation of our debt or other material obligations. In addition, we received a notification from the NYSE on November 30, 2016 that our market capitalization had fallen below the NYSE’s continued listing standard because our average market capitalization had fallen below $50 million over a trailing 30 trading-day period and our last reported stockholders’ equity was less than $50 million.

ACTIVITIES BY ASSET

~~Gabon~~

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame ~~Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields~~Marin Block on behalf of a consortium of ~~four~~ companies. As of September 30, ~~2017,~~2023, production operations in the Etame Marin block included ~~seven~~fifteen platform wells, plus ~~three~~two subsea wells ~~across all fields~~ tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery and processing ~~storage~~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 ~~offloading the oil from a~~offloaded. The leased ~~Floating, Production, Storage and Offloading vessel (“FPSO”)~~FSO is anchored to the seabed on the block. The ~~FPSO~~Etame field currently has a combined total of seventeen producing wells. During the three months ended September 30, 2023 and 2022, production ~~limitations~~from the block was 1,550 million barrels ("MBbls") (792 MBbls, net) and 1,647 MBbls (842 MBbls, net), respectively, as discussed below in “Results of ~~approximately 25,000 BOPD~~Operations”. During the nine months ended September 30, 2023 and ~~30,000 barrels~~2022, production from the Etame Marin block was 4,740 MBbls (2,425 MBbls net) and 4,701 MBbls (2,405 MBbls net), respectively.

Egypt

In Egypt, 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 ~~total fluids per day.~~our Egyptian blocks are production sharing contracts ("PSC") 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 September 30, 2023, production from the Eastern Desert was 1,076 MBbls (732 MBbls, net) as discussed below in “Results of Operations.” During the nine months ended September 30, ~~2017 and 2016,~~2023, production from the ~~block~~Eastern Desert was ~~approximately 4,268~~3,032 MBbls ~~(1,154~~(2,074 MBbls, net) ~~and 4,835 MBbls (1,181 MBbls net), respectively.~~.

~~During the first quarter of 2016, we conducted workover operations on two Avouma field wells. An Electrical Submersible Pump (“ESP”) system was replaced successfully in one~~

The SGZ-6X well ~~but the workover operations on the second well were suspended due to operational problems with its ESP. During the second and third quarters of 2016, the ESPs~~ in the South ~~Tchibala 2-H well and~~Ghazalat concession in the Avouma 2-H well also failed. These wells were temporarily shut-in, but through our utilizing a lower-cost hydraulic workover unit to replace the failed ESP systems, the two wells were placed back on production in December 2016 and January 2017, respectively.Western Desert is currently suspended pending further evaluation.

Canada

In ~~July 2017, the ESP~~Harmattan, Canada, we own production and working interests in the ~~South Tchibala 2-H well failed, resulting~~Cardium light oil and Mannville liquids-rich gas assets. This property produces oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the ~~well being temporarily shut-in.~~

~~In October 2017, we began workover operations on the South Tchibala 1-HB well. These operations were successfully completed in November 2017,~~Lower Mannville and ~~the well was returned~~Rock Creek formations at vertical depths of 2,000 to ~~production. We began workover operations on the South Tchibala 2-H well in November 2017. This~~2,600 meters. All gas is ~~expected~~delivered to ~~result in an increase in production~~a third party non-operated gas plant for ~~the fourth quarter. In addition the fourth quarter is expected to have higher production expenses related to the workover costs.~~

processing. During ~~July 2017, production was temporarily shut-in for periodic maintenance, and as a result, production volumes were lower in~~ the three months ended September 30, ~~2017 and~~2023, production from our Canadian assets was 261 thousand barrels of oil equivalent ("MBoe") to our working interest (210 MBoe, net) as discussed below in “Results of Operations." During the nine months ended September 30, 2023, production ~~expense increased as a result~~from our Canadian assets was 775 MBoe to our working interest (672 MBoe, net).

Equatorial Guinea

As of September 30, 2023, we had $10.0 million recorded for the book value of the ~~maintenance-related costs.~~

~~Equatorial Guinea~~

~~We have a 31% working~~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 ~~an undeveloped portion~~the Block to 60.0%. This increase of ~~a block offshore Equatorial Guinea that we acquired in 2012. It is currently unlikely that we will be making any near-term expenditures with respect~~14.1% participating interest increases our future payment to ~~any development~~GEPetrol to $6.8 million at first commercial production of ~~this property. Before beginning exploration, we and our partners will need~~the Block. In March 2023, Atlas voted to ~~evaluate the timing and budgeting for development and exploration activities under a development and production area~~participate in the ~~block, including~~Venus Development. Amendment 5 of the ~~approval~~PSC was approved by all parties in March 2023 with this updated participating interest, and execution of athe Venus development plan has been initiated. VAALCO, as operator, is in the process of working through the project charter and ~~production plan. Our production sharing contract covering this development and production area~~timing of key milestones. In addition, the amendment to the Joint Operating Agreement requires final ratification by all parties thereto.

The Block P PSC provides for a development and production period of 25 years from the date of approval of a development and production ~~plan. We are in continued discussions~~plan for the area associated with the ~~Minister~~Venus development. The PSC also includes the portions of Block P not associated with the ~~Ministry of Mines and Hydrocarbons regarding the timing of any possible development plan.~~

~~Discontinued Operations~~Block P - ~~Angola~~Venus development.

~~In November 2006, our Angolan subsidiary,~~ ~~Vaalco Angola~~ (Kwanza), Inc., (“VAALCO Angola”), signed a production sharing contract for Block 5 offshore Angola (“PSA”). The four year primary term, referred to as the Initial Exploration Phase (“IEP”), with an optional three year extension, awarded VAALCO Angola exploration rights to 1.4 million acres offshore central Angola, with a commitment to drill two exploratory wells. The IEP was extended on two occasions to run until December 1, 2014. In October 2014, VAALCO Angola entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required VAALCO Angola and the co-participating interest owner, the Angolan national oil company, Sonangol P&P, to drill two additional exploration wells. VAALCO Angola’s working interest is 40%, and it carries Sonangol P&P, for 10% of the work program. On September 30, 2016, VAALCO Angola notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, VAALCO Angola notified the national concessionaire, Sonangol E.P., that it was withdrawing from the PSA. Further to the decision to withdraw from Angola, VAALCO Angola has taken actions to begin reducing its office in Angola and reducing future activities in Angola upon the approval of VAALCO Angola’s withdrawal. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented.

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~~Drilling Obligation~~

~~Under the PSA,~~ ~~Vaalco Angola~~and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases under the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each exploration well for which a drilling obligation remains under the terms of the PSA, of which VAALCO Angola’s participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2017 and December 31, 2016, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. However, we are currently engaged in discussions with newly appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid will be substantially less than the accrued amount.

~~Other Matters – Partner Receivable~~

On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery and default interest of $3.2 million is included in Loss from discontinued operations, net of tax for the nine months ended September 30, 2016.

~~LIQUIDITY AND~~ CAPITAL RESOURCESAND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 are as follows:

							Nine Months Ended September 30,
	Nine Months Ended September 30,				Increase		2023			2022			Increase (Decrease) in 2023 over 2022
	2017		2016		(Decrease)		*(in thousands)*
Net cash provided by operating activities before changes in operating assets and liabilities							$	117,343		$	95,850		$	21,493
Net change in operating assets and liabilities								54,483			33,906			20,577
Net cash provided by (used in) continuing operating activities								171,826			129,756			42,070
Net cash used in discontinued operating activities								(15	)		(57	)		42
Net cash provided by (used in) operating activities								171,811			129,699			42,112
	(in thousands)
Net cash provided by (used in) operating activities	$	3,232	$	(36)	$	3,268
Net cash provided by (used in) investing activities		(1,123)		1,655		(2,778)		(77,365	)		(103,853	)		26,488
Net cash used in financing activities		(3,720)		(93)		(3,627)
Net change in cash and cash equivalents	$	(1,611)	$	1,526	$	(3,137)

Net cash provided by (used in) in financing activities								(42,382	)		(8,075	)		(34,307	)
Effects of exchange rate changes on cash								(321	)		—			(321	)
Net change in cash, cash equivalents and restricted cash							$	51,743		$	17,771		$	33,972

The $21.5 million increase in net cash provided by ~~our~~ operating activities before changes in operating assets and liabilities during the nine months ended September 30, 2023 was due to a $73.1 million increase in depreciation expense and $42.6 million lower cash settlements on derivative contracts partially offset by a prior year $42.7 million derivative gain and a $41.8 million decrease in deferred tax expense. The net increase in changes provided by operating assets and liabilities of $20.6 million for the nine months ended September 30, ~~2017~~2023 compared to the same period of ~~2016~~2022 was primarily related to ~~a $20.6~~positive changes in trade receivable, receivables accounts with joint venture owners, other long-term assets and foreign income taxes payable (collectively $66.8 million). Partially offsetting these changes were negative changes in accounts payable and accrued liabilities and other (collectively negative $50.5 million).

The $26.5 million increase in cash generated by continuing operations which in large part was the result of higher 2017 crude oil prices and lower operating costs and expenses. This overall improvement was offset by a reduction in cash generated by our discontinued operation for the first nine months of 2017 totaling $17.4 million. The decrease in net cash generated by discontinued operations was the result of a benefit received in the nine months September 30, 2016 of $19.0 million from our Angolan joint interest partner in payment of partner receivables.

~~Property and equipment expenditures have historically been our most significant use of cash~~used in investing ~~activities. During~~activities during the nine months ended September 30, ~~2017, these~~2023 was due to capital spending costs associated with the development drilling programs in Egypt and Canada not exceeding prior year expenditures ~~on a cash basis were $1.3 million, primarily related to equipment purchases. This compares to $12.8 million in property and equipment~~along with reduced current year expenditures ~~included in capital expenditures~~ for Gabon. For the nine months ended September 30, ~~2016. See “Capital Expenditures” below~~2022, cash used in investing activities was due to increases in capital spending in 2022 for ~~further discussion.~~ the Etame 8-H well, the Avouma 3H-ST well, ETBSM 1HB-ST well, the Etame field reconfiguration and other items to support the 2021/2022 drilling campaign.

Net cash ~~provided by investing~~used in financing activities ~~for the 2016 period also included a $15.3 million benefit from the decrease in restricted cash.~~

~~Capital Expenditures~~

~~During~~during the nine months ended September 30, ~~2017,~~2023 included $20.2 million for dividend distributions, $17.5 million for treasury stock repurchases made under our stock repurchase plan or as a result of tax withholding on options exercised and on vested restricted stock, and $5.2 million of principal payments on our finance leases partially offset by $0.6 million in proceeds from options exercised. For the nine months ended September 30, 2022, cash used in financing activities included $5.8 million for dividend distributions, $0.8 million for treasury stock repurchases, as a result of tax withholding on options exercised and vested restricted stock, $1.5 million of costs capitalized associated with our credit facility and $0.2 million of principal payments on our finance leases partially offset by $0.3 million in proceeds from options exercised.

Capital Expenditures

For the nine months ended September 30, 2023 we ~~made~~had accrual basis capital expenditures attributable to continuing operations of ~~$1.1 million. At~~$63.3 million compared to $121.6 million accrual basis capital expenditures for the same period in 2022. For the nine months ended September 30, ~~2017,~~2023, our cash spending primarily 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.

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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.

Commodity Price Hedging

The price we ~~had no material commitments~~receive for our crude oil, natural gas and NGLs significantly influences our revenue, profitability, liquidity, access to capital ~~expenditures~~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 ~~made~~volatile in ~~2017~~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 ~~future years. We expect any capital expenditures made during 2017 will be funded by cash on hand and~~ cash flow from ~~operations.~~

~~Abandonment Obligations~~

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 ~~an agreed~~not designated any of our derivative contracts as fair value or cash ~~funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. Based upon the abandonment study completed~~flow hedges. The changes in ~~January 2016, the abandonment cost estimate used for this purpose is approximately $61.1 million ($19.0 million net to VAALCO) on an undiscounted basis. The obligation for abandonment~~fair value of the ~~Gabon offshore facilities is~~contracts are included in the ~~“Asset retirement obligations” line item on our~~unaudited condensed consolidated ~~balance sheets. Through September 30, 2017, $27.4 million ($8.5 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets”~~statements of operations and comprehensive income. We record such derivative instruments as ~~“Abandonment funding” on our~~assets or liabilities in the unaudited condensed consolidated balance sheet. ~~The next funding~~

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is expected to be $7.4 million ($2.3 million net to VAALCO) and paid in December 2017; however, future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.

~~Capital Resources~~

~~Credit Facility~~

Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the credit facility with the IFC and cash balances on hand. The current $11.2 million in principal outstanding under our Amended Term Loan Agreement matures in June 2019, and requires quarterly principal and interest payments on the amounts currently outstanding continuing through June 30, 2019. Interest accrues on the unpaid balance at the per annum rate of LIBOR plus 5.75%. The current portion of the outstanding debt was $7.5 million as of September 30, 2017. Our repayment obligations under this facility require us to pay installments of principal totaling $2.0 million for the remainder of 2017, $6.7 million in 2018 and $2.5 million in 2019. We may make no further borrowings under the terms of the Amended Term Loan Agreement.

~~The indebtedness under our amended loan agreement is secured by the assets of our Gabon subsidiary, VAALCO Gabon S.A. and is guaranteed by VAALCO Energy, Inc., as the parent company.~~

The Amended Term Loan Agreement contains a number of restrictive covenants that impose significant operating and financial restrictions on us. These covenants restrict our ability to engage in certain actions, including potentially limiting our ability to sell assets, make future borrowings or incur other additional indebtedness. Our ability to meet our quarter-end net debt to EBITDAX ratio and our debt service coverage ratio can be affected by events beyond our control, including changes in commodity prices.

Under the Amended Term Loan Agreement, quarter-end net debt to EBITDAX (as defined in the loan agreement) must be no more than 3.0 to 1.0. Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at ~~semi-annual review period~~. Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain. Factors that could impact our quarter-end financial covenants in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. We are in compliance with all financial covenants as of September 30, 2017, and we expect to be in compliance with these covenants through maturity. However, there can be no assurance that we will be able to comply with these financial covenants in future periods. In addition, if we receive any waivers or amendments to our Amended Term Loan Agreement, the lender may impose additional operating and financial restrictions on us.

A breach of the covenants under our Amended Term Loan Agreement could result in an event of default under the agreement. Such a default may allow the lender to accelerate payment of the indebtedness under the agreement and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. Furthermore, if we were unable to repay the amounts due and payable under the loan agreement, the lender could proceed against the collateral that we granted to it to secure that indebtedness.

C~~ash~~Cash on Hand

At September 30, ~~2017,~~2023, we had unrestricted cash of ~~$18.9~~$103.4 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 ~~and Mutamba Iroru blocks~~block in Gabon, we enter into ~~project related~~project-related activities on behalf of our working interest ~~partners.~~joint venture owners. We generally obtain advances from ~~partners~~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 for the foreseeable future.~~operations.

We currently sell all our crude oil production from Gabon under a ~~term contract that ends in January 2018. Pricing under~~COSMA with Glencore. Under the ~~contract is~~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 ~~prices~~ 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 nine months ended September 30, 2023, sales to Egypt were split between Mercuria and the EGPC. Mercuria purchased oil in January and August, while the EGPC performed May, June, and September liftings. 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. For the three and nine months ended September 30, 2023, revenues in Canada were concentrated in three separate customers. For the nine months ended, these customers were Plains Midstream (41.9%), AltaGas (18.4%), and PetroGas Energy (28.40%). For the three months ended September 30, 2023, these customers were Plains Midstream (51.0%), AltaGas (17.5%), and PetroGas Energy (19.80%).

Settlement of accounts receivable in Canada occur on the 25th of the following month after production.

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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 ~~expect~~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. We believe that the 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 the Company'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 ~~able~~required to ~~extend or enter into~~pay an additional $10.0 million on February 1 for each of the next three years. In addition, we have committed to spending a ~~new contract on comparable terms on or before January 2018.~~

~~Liquidity~~

~~As discussed above, our revenues, cash flow, profitability, oil and natural gas reserve values and future rates~~minimum of ~~growth are substantially dependent upon prevailing prices~~$50.0 million over each five-year period for ~~oil and natural gas.~~the 15 years of the primary term (totaling $150.0 million). Our ability to ~~borrow funds~~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 ~~obtain additional capital~~certain financial, business, legislative, regulatory and other factors beyond our control.

RBL Facility Agreement and Available Credit

Our Facility Agreement with Glencore is available to support our exploration and development programs as well as our corporate activities. As of September 30, 2023, there were no borrowings under the Facility. As of October 1, 2023, the amount available to be drawn under the facility was $43.8 million. On April 1 and October 1 of each year during the term of the Facility, committed amount available to be drawn will be reduced by $6.25 million. The Facility provides for determination of the borrowing base asset based on ~~attractive terms~~our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is ~~also substantially dependent~~determined and re-determined by the Lenders on ~~oil~~March 31 and ~~natural gas prices. After~~September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base. 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”).

Each loan under the Facility originally bore an interest at a ~~period~~rate equal to LIBOR plus a margin (the “Applicable Margin”) of ~~low commodity prices, oil~~(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. On October 3, 2023 the Company signed an Amended and ~~gas prices have stabilized at levels which are currently adequate~~Restated Facility Agreement to ~~generate cash from operating activities for our continuing operations.~~ replace the LIBOR component, in the original Facility Agreement, with a SOFR plus credit adjustment spread rate. The SOFR plus credit adjustment spread rate is intended to approximate the LIBOR component in the original Facility Agreement and the LIBOR component is was replaced due to concerns about the sustainability of LIBOR as a global reference rate.

We ~~believe that at current prices, cash generated from continuing operations together~~were in compliance with ~~cash on hand~~the financial covenants contained in the Facility at September 30, ~~2017~~2023.

Cash Requirements

Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, dividend payments, funding of our share buyback program, merged concession agreement, future lease payments and abandonment funding, each of which is discussed below or in the footnotes to the financial statements.

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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 ~~adequate~~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 September 30, 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.

Merged Concession Agreement – Under the Merged Concession Agreement, we will make three annual payments of $10.0 million each to the EGPC beginning February 1, 2024, until February 1, 2026.

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.

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 ~~cash requirements during~~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 ~~remainder of 2017~~subsequent sanctions imposed on the Russian Federation has, and ~~through December 31, 2018.~~

~~As discussed in Note 7~~may continue to have, a destabilizing effect on the ~~condensed consolidated financial statements, we have put contracts in place at September 30, 2017 which limits our exposure to a decline~~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, ~~through December 31, 2017.~~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.

~~All~~

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 ~~proved reserves~~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 ~~related~~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+. However, the Company has not received any mandate to reduce its current oil production from the Etame Marin block ~~offshore Gabon. The current term for exploitation~~as a result of the ~~reserves~~OPEC+ initiatives.

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ESG and Climate Change Effects – Sustainability matters continue to attract considerable public, regulatory and scientific attention. In particular, we expect continued required reporting 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) and freshwater use. This increased attention to climate change and environmental conservation coupled with stepped up government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, 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 ~~Etame Marin block ends in June 2021,~~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 reporting requirements, including establishing and communicating short and long-term goals and targets, furthering the reduction of our carbon footprint and measurement of GHG emissions. Sustainability remains an important topic to us, and we are ~~focused on extending~~in the ~~license~~process of developing a multi-year plan to establish and document our progress in achieving goals we set for ~~the block, which, if accompanied by a successful drilling program, could favorably~~ourselves across all areas of sustainability. Our plans will enable us to monitor and improve ~~our long-term liquidity. Except~~matters related to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced, which would negatively impact our long-term liquidity. In addition, our short-termESG and ~~long-term liquidity are impacted by the changes in crude oil prices.~~climate change going forward.

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~~OFF-BALANCE SHEET ARRANGEMENTS~~

In connection with the charter of the FPSO (see “— Activities by Asset — Gabon — Offshore-Etame Marin Block”), we, as operator of the Etame Marin block, guaranteed all of the lease payments under the charter through its contract term, which expires in September 2020. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of our partners for their respective shares of the payments. Our net share of the charter payment is 31.1%, or approximately $9.7 million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded a liability of $0.5 million and $0.7 million as of September 30, 2017 and December 31, 2016, respectively, representing the guarantee’s fair value. The guarantee of the offshore Gabon FPSO lease has $93.1 million in remaining gross minimum obligations for the total amount of charter payments at September 30, 2017. There have been no other material off-balance sheet arrangements entered into since December 31, 2016.

~~COMMITMENTS AND CONTRACTUAL OBLIGATIONS~~

Other than our borrowing of $4.2 million under the Additional Term Loan Agreement discussed in Note 5 to the condensed consolidated financial statements, there have been no significant changes to our commitments and contractual obligations subsequent to December 31, 2016.

CRITICAL ACCOUNTING POLICIES

There have been no material changes to our critical accounting policies subsequent to December 31, ~~2016.~~2022.

NEW ACCOUNTING STANDARDS

See Note 2 to the ~~condensed consolidated financial statements.~~Financial Statements.

RESULTS OF OPERATIONS

Three ~~months ended~~Months Ended September 30, ~~2017 compared~~2023 Compared to the ~~three months ended~~Three Months Ended September 30, ~~2016~~2022

~~We reported net loss~~

Net income for the three months ended September 30, ~~2017 of $0.3~~2023 was $ 6.1 million compared to a net ~~loss~~income of ~~$14.8~~$ 6.9 million for the same period of ~~2016. The net loss~~2022. See discussion below for the three months ended September 30, 2017 is inclusive of the loss from discontinued operations for the same period of $0.2 million. The net loss for the three months ended September 30, 2016 was inclusive of the loss from discontinued operations for the same period of $15.8 million. Further discussion of results by significant line item follows.changes in revenue and expense.

~~Oil and~~

Crude oil, natural gas and NGL revenuesincreased ~~$3.5~~$38.2 million, or approximately ~~24.2%~~49%, to $ 116.3 million during the three months ended September 30, ~~2017 compared to~~2023 from $ 78.1 million for the same period ~~of 2016.~~in the prior year. The revenue increase ~~in revenue~~ is attributable to higher ~~realized oil prices, due to increases~~volumes sold in Gabon and the addition of the Egypt and Canada segments acquired in the ~~Dated Brent market price as well as higher volumes attributable~~TransGlobe acquisition, partially offset by significantly lower realized sales prices compared to the ~~Sojitz acquisition. This was offset in part by an overall decrease in sales volumes.~~prior period.

	Three Months Ended September 30,
	2023		2022		Increase/(Decrease)
	*(in thousands except per Boe information)*
Net crude oil, natural gas and NGLs sales volume (MBoe)		1,812		731		1,081
Average crude oil, natural gas, and NGLs sales price (per Boe)	$	63.41	$	103.61	$	(40.20	)

Net crude oil, natural gas, and NGLs revenue	$	116,269	$	78,097	$	38,172

Operating costs and expenses:
Production expense		39,956		23,312		16,644
FPSO demobilization		—		8,867		(8,867	)
Exploration expense		1,194		56		1,138
Depreciation, depletion and amortization		32,538		8,963		23,575
General and administrative expense		6,216		1,979		4,237
Credit losses and other		822		1,020		(198	)
Total operating costs and expenses		80,726		44,197		36,529
Other operating expense, net		5		—		5
Operating income	$	35,548	$	33,900	$	1,648

Table of Contents

The revenue changes in the three months ended September 30, ~~2017~~2023 compared to the ~~three months ended September 30, 2016,~~same period in 2022 identified as related to changes in price or volume, are shown in the table below:

*(in thousands)*
Price	$	(72,831	)
Volume		111,983
Other		(980	)
	$	38,172

(1)

The price in the table above excludes revenues attributed to carried interests

The table below shows net production, sales volumes and realized prices for both periods.

	Three Months Ended September 30,
	2023		2022
Net crude oil, natural gas and NGLs production (MBoe)		1,734		842
Net crude oil, natural gas, and NGL sales (MBoe)		1,812		731

Average realized crude oil, natural gas and NGLs price ($/Boe)	$	63.41	$	103.61
Average Dated Brent spot price* ($/Bbl)		86.65		99.90

*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil, natural gas and NGL revenues increased $38.2 million, or approximately 49%, during the three months ended September 30, 2023 compared to the same period of 2022.

Gabon

Three Months Ended September 30,

2017

2016
Gabon net oil production (MBbls)

341

347

Gabon net oil sales (MBbls)

336

343
U.S. net oil sales (MBbls)

—

1
Net oil sales (MBbls)

336

344
Net natural gas sales (MMcf)

—

32
Net oil equivalents (MBOE)

336

349

Average realized oil price ($/Bbl)

$
51.10

$
40.00
Average realized natural gas price ($/Mcf)

—

2.37
Weighted average realized price ($/BOE)

51.10

39.61
Average Dated Brent spot* ($/Bbl)

52.10

45.80
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

~~Table of Contents~~

~~Production expenses~~ ~~increased $3.2 million, or approximately 44.3%, in~~Company’s total revenue during the three months ended September 30, ~~2017 compared~~2023. This compares to the ~~same period~~$ 78.1 million of ~~2016. Excluding workovers (a component of total production expenses),~~revenue contributed by the increase is primarily the result of: our increased ownership interest in the Etame Marin block of Gabon after the November 2016 Sojitz acquisition, costs related to the planned maintenance turnaround, asset integrity work performedSegment during the planned turnaround and costs associated with certain regulatory requirements in Gabon. Workover costs were minimal in the 2017 period, whereas for the 2016 period we had an adjustment for estimated costs.

~~Depreciation, depletion and amortization (“DD&A”)~~ ~~costs were not materially different from~~ the three months ended September 30, ~~2017 compared to the same period of 2016.~~

~~General and administrative expenses~~ ~~increased $0.9 million, or approximately 55.1%~~2022. The total barrels lifted in the three months ended September 30, 2017 compared to the same period of 2016. Personnel costs were higher in 2017 as a result of higher stock-based compensation as 2016 included the benefit related to employee forfeitures. This was offset by lower wages and employee benefits in 2017.

~~Bad debt expense and other~~ ~~was not materially different~~Gabon for the three months ended September 30, ~~2017 and 2016 related primarily~~2023 was slightly lower than the three months ended September 2022, mainly due to three lifting occurring in the ~~allowance for~~2022 period compared to two lifting in the ~~Value added tax receivable (“VAT”).~~

~~Other operating expenses~~ ~~for~~2023 period. This was compounded by the Gabon per barrel price received during the three months ended September 30, ~~2016 included~~ ~~$0.2 million related~~2023 which was $19.49 less than the price received in 2022. Our share of crude oil inventory, excluding royalty barrels, was approximately 333,396 barrels and 143,972 barrels at September 30, 2023 and 2022, respectively.

Nine Months Ended September 30, 2023 Compared to the Nine Months Ended September 30, 2022

Net income for the nine months ended September 30, ~~2017 of $6.2~~2023 was $16.4 million compared to a net ~~loss~~income of ~~$22.9~~$34.1 million for the same period of ~~2016. These amounts of income (loss) were inclusive of our loss from discontinued operations~~2022. See discussion below for ~~the nine months ended September 30, 2017 of $0.5 million,~~changes in revenue and ~~loss from discontinued operations for the nine months ended September 30, 2016 of $8.0 million. Further discussion of results by significant line item follows.~~ expense.

Crude oil, natural gas and NGLs revenuesincreased ~~$15.4~~$48.2 million, or approximately ~~34.7%~~19%, to $305.9 million during the nine months ended September 30, ~~2017 compared to~~2023 from $257.7 million for the same period ~~of 2016. A substantial portion of~~in the prior year. The revenue increase ~~in revenue~~ is ~~related to higher realized oil prices as well as higher volumes~~ attributable to the ~~Sojitz acquisition. This was~~addition of the Egypt and Canada segments acquired in the TransGlobe acquisition, partially offset ~~in part~~ by ~~an overall decrease in~~lower realized sales ~~volumes.~~prices.

The revenue changes in the nine months ended September 30, ~~2017~~2023 compared to the ~~nine months ended September 30, 2016~~same period in 2022 identified as related to changes in price or volume, are shown in the table below:

The table below shows net production, sales volumes and realized prices for both periods.

*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil, natural gas and NGL revenues increased $48.2 million, or approximately 19%, during the nine months ended September 30, 2023 compared to the same period of 2022.

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each ~~quarter from the FPSO,~~year and thus crude oil sales do not always coincide with volumes produced in any given ~~quarter. We made~~year. The Company’s Gabon segment contributed $171.9 million of revenue to the Company’s total revenue during the nine ~~liftings~~months ended September 30, 2023. This compares to the $257.7 million of revenue contributed by the Segment during the nine months ended September 30, 2022. The total barrels lifted in Gabon for the nine months ended September 30, ~~2017 and 2016. Our share~~2023 was less than the barrels lifted during the same period in 2022, mainly due to the timing of ~~oil inventory aboard~~liftings. In addition, the ~~FPSO, excluding royalty barrels, was approximately 42,000 and 39,000 barrels at September 30, 2017 and 2016, respectively.~~

~~Production expenses~~ ~~increased $2.4 million, or approximately 9.3%, in~~Gabon per barrel price received during the nine months ended September 30, ~~2017 compared~~2023 was $28.80 less than the price received in 2022. Our share of crude oil inventory, excluding royalty barrels, was approximately 333,396 and 143,972 barrels at September 30, 2023 and 2022, respectively.

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the same period of 2016, primarily as a result of our increased ownership in the Etame Marin block of Gabon after the November 2016 Sojitz acquisition, costs related to the planned maintenance turnaround, asset integrity work performed during the planned turnaround, costs associated with certain regulatory requirements in Gabon, custom fees and FPSO cost escalation.

~~Depreciation, depletion and amortization (“DD&A”)~~ ~~decreased $0.2 million, or approximately 4.3%, in~~government, EGPC. During the nine months ended September 30, ~~2017 compared~~2023, the oil sold in Egypt was through third party sales to Mercuria Energy during the first quarter, and through direct sales to EGPC during the second quarter. The company sold to both the EGPC and Mercuria during the third quarter. The Company’s Egypt segment contributed $106.4 million of revenue to the same period of 2016 due to the favorable impact of depleting our costs over a higher reserve base as a result of improvements in estimated reserves identified at December 31, 2016 as well as lower production.

~~General and administrative expenses~~ increased $0.8 million, or approximately 10.4% in the nine months ended September 30, 2017 compared to the same period of 2016. The increase was primarily related to higher legal fees and accounting and auditing costs offset by lower personnel costs. Personnel costs were lower in 2017 as a result of lower wages and employee benefits offset by higher stock-based compensation as 2016 included the benefit related to employee forfeitures.

~~Bad debt expense and other~~Company’s total revenue for the nine months ended September 30, ~~2017 and 2016 related primarily to~~2023. At September 30, 2023, the ~~allowance on~~Company’s Egypt segment had zero barrels in oil inventory. Since the ~~Value added tax (“VAT”) receivable.~~

~~Other operating expenses~~ Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the nine months ended September 30, ~~2016 included $2.1~~2022.

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $27.6 million ~~accrued for certain unpaid payroll taxes in Gabon which were not paid pertaining~~of revenue to ~~labor provided to us over a number of years by a third-party contractor and $7.6 million, net to VAALCO, of expense associated with~~ the ~~demobilization and release of the contracted drilling rig. In June 2016, we reached an~~ agreement with the drilling contractor to pay less than our originally estimated maximum day rate, plus demobilization costs, in seven equal monthly installments beginning in July 2016. In January 2017, we resolved the Gabon payroll tax obligation.

~~General and administrative related to shareholder matters~~��Company’s total revenue for the nine months ended September 30, ~~2016 reflects offsetting insurance proceeds related to costs incurred on shareholder litigation that was settled~~2023. Since the Company acquired its Canadian segment in ~~2016.~~

~~Other, net~~ the fourth quarter of 2022, there are no comparable revenues for the nine months ended September 30, ~~2017 and 2016 consists primarily of foreign currency gains and derivative instrument losses as discussed in Note 7 to the condensed consolidated financial statements.~~2022.

~~Interest expense~~Production expenses increased $39.6 million, or approximately 59%, for the nine months ended September 30, ~~2017 and 2016 relates~~2023 to ~~our “Term Loan” as discussed in Note 5 to the condensed consolidated financial statement.~~

~~Income tax expense~~ ~~increased $2.2~~$106.8 million ~~in the nine months ended September 30, 2017 compared to~~from $67.1 million for the same period ~~of 2016. Income tax~~in the prior year. The increase in production expense ~~in both periods is~~was primarily ~~attributable~~driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to ~~our operations in Gabon~~the added production from the now completed 2021/2022 drilling campaign. VAALCO has seen inflationary pressure on personnel and ~~is higher in 2017 than income tax for the comparable 2016 period as~~contractor costs. On a ~~result of higher revenues.~~

~~Loss from discontinued operations~~per barrel basis, production expense, excluding workover expense and stock compensation expense, for the nine months ended September 30, ~~2017 is attributable~~2023 decreased to ~~our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The loss~~$22.32 per barrel from ~~discontinued operations~~$29.10 per barrel for the ~~2017 period is related to ongoing administrative costs.~~nine months ended September 30, 2022 primarily as a result of higher sales volumes. For the nine months ended September 30, ~~2016,~~2023, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic. For the nine months ended September 30, 2023 the costs associated with proactive measures related to COVID were not material. For the nine months ended September 30, 2022, we incurred $1.6 million in higher costs related to the proactive measures taken in response to the pandemic.

FPSO Demobilization for the nine months ended September 30, 2023 was $5.7 million. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.7 million in decommissioning fees, which was reported as a separate line item on the income statement. A similar expense of $8.9 million was recorded for the nine months ended September 30, 2022 for costs incurred to retire the FPSO as we transitioned the block to the FSO.

Exploration expense for the nine months ended September 30, 2023 was $1.3 million due primarily to the abandonment of the East Arta - 54 appraisal well. In 2022, exploration expense was not material to our results.

Depreciation, depletion and amortization costs increased $73.1 million, or approximately 335% for the nine months ended September 30, 2023 to $95.0 million from $21.8 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense for the nine months ended September 30, 2023 compared to nine months ended September 30, 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. In addition, new wells were brought online in 2023 for both Egypt and Canada, which also increased depreciation, depletion and amortization expense.

General and administrative expenses increased $6.3 million, or 60%, for the nine months ended September 30, 2023 to $16.8 million from $10.5 million for the same period in the prior year. The increase in general and administrative expenses is primarily due increased professional fees, accounting and legal services, and salaries and wages.

Credit losses and other increased by $0.3 million to $2.4 million for the nine months ended September 30, 2023 from $2.1 million for the nine months ended September 30, 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 nine months ended September 30, 2023, we recognized an additional amount to the credit loss allowance of $0.6 million for crude oil delivered to the refinery during the nine months. For the nine months ended September 30, 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 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 ~~discontinued operations primarily~~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 nine months ended September 30, 2023 we added $1.5 million to the allowance account for the current year's 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 Financial Statements.

Other operating expense, net for each of the nine months ended September 30, 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 Financial Statements. Derivative loss decreased by $35.3 million, or approximately 94.0% to a loss of $2.3 million for the nine months ended September 30, 2023 from a loss of $37.5 million during the same period in the prior year. Derivative gains (losses) for the nine months ended September 30, 2022 are a result of ~~$3.1~~the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the nine months ended September 30, 2022. The same increase in price occurred, but to a lesser extent, in 2023. 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 June 2024.

Interest expense, net was $5.4 million for the nine months ended September 30, 2023 compared to an expense of $0.4 million during the same period in 2022. The increase of net interest expense for the nine months ended September 30, 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 ~~tax on financial~~decreased by $9.0 million to an expense of $1.5 million for the nine months ended September 30, 2023 from an expense of $10.5 million for the nine months ended September 30, 2022. Other (expense) income, net normally consists of foreign currency gains and ~~$15.0~~(losses). However, the nine months ended September 30, 2023, also included $1.4 million ~~accrual~~expense from a transition period adjustment of the bargain purchase gain related to the TransGlobe acquisition as discussed in Note 3 to the Financial Statements. For the nine months ended September 30, 2022, $7.6 million of transactions costs associated with the TransGlobe acquisition is the primary driver for the ~~potential payment of drilling obligations offset by $7.6 million of bad debt recovery and $3.2 million of collected default interest.~~activity along with foreign currency losses.

Income tax expense (benefit) for the nine months ended September 30, 2023 was an expense of $52.2 million. This is comprised of current tax expense of $51.5 million and $0.7 million of deferred tax expense. Income tax expense (benefit) for the nine months ended September 30, 2022 was an expense of $64.5 million. This is comprised of current tax expense of $24.9 million and $39.5 million of deferred tax expense. The deferred income tax expense for the nine months ended September 30, 2022 included a $20.2 million deferred tax benefit from the reversal of the valuation allowance.

We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.

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 ~~Fran,~~Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon isare 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.

~~The floating interest rate on our amended loan agreement exposes us to risks associated with changes in interest rates (LIBOR). At~~ As of September 30, ~~2017 and December 31, 2016,~~2023, we had ~~$11.0~~net monetary assets of $29.6 million (XAF 18,384.4 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $2.7 million reduction in the value of these net assets. For the three and nine months ended September 30, 2023, we had expenditures of approximately $14.3 million and ~~$14.4~~$38.8 million, respectively, ~~which include deferred financing costs~~(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 ~~$0.3 million and $0.6 million, respectively, in borrowings outstanding with~~ the ~~IFC. Fluctuations in floating interest rates will cause our interest costs to fluctuate. For~~Canadian dollar against the US dollar would increase the value of the net assets for the nine months ended September 30, ~~2017 and 2016,~~2023 by approximately $0.5 million. Conversely, a 10% increase in the ~~average effective interest rates on our debt, excluding commitment fees, were 6.87% and 5.04%, respectively. If the balance~~value of the ~~debt~~Canadian dollar against the US dollar would decrease the value of the net assets for the nine months ended September 30, 2023 by approximately $0.6 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 September 30, ~~2017 were to remain constant,~~2023, we estimate that a ~~1% change~~10% increase in ~~market interest rates would impact our cash flow by an estimated $0.1 million per year. As future quarterly repayments~~the value of the ~~loan reduce~~Egyptian pound against the ~~principal amount~~US dollar would increase the cash value for the nine months ended September 30, 2023 by $0.8 million. Conversely, a 10% decrease in the value of the ~~Term Loan,~~Egyptian pound against the US dollar would decrease our US dollar cash ~~flow becomes less sensitive to fluctuations in interest rate.~~value for the nine months ended September 30, 2023 by $0.6 million.

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.

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. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline which continued through the first half of 2016. Current prices remain significantly lower than they were in years prior to 2015. 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 ~~336~~665 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a ~~$1.7~~$3.3 million decrease per quarter ~~($6.8 million annualized)~~ in revenues and operating income (loss) and a ~~$1.4~~$3.0 million decrease per quarter ~~($5.8 million annualized)~~ in net ~~income.~~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 209 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $1.0 million decrease per quarter in revenues and operating income (loss) and a $0.8 million decrease per quarter in net income (loss).

As of September 30, ~~2017,~~2023, we had unexpired ~~oil puts with a fair value asset position~~derivative instruments outstanding covering approximately 705 MBbls of ~~$0.1 million. While these crude oil derivative contracts are~~production through June 30, 2024. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they ~~are~~were not designated as hedges for accounting purposes. See Note 8 to the Financial Statements for further discussion.

Changes in market interest rates affect the amount of interest owed on outstanding balances under our Facility. However, as of September 30, 2023 we had no amounts drawn under the facility. The ~~contracts~~commitment fees on the undrawn availability under the Facility are ~~measured at fair value at the end of each quarter, with~~not subject to changes in ~~value flowing through net income. See Note 7 to the condensed consolidated financial statements for further information about these contracts, their fair value and their~~interest rates. Additionally, changes in market interest rates could impact ~~on our net income.~~interest costs associated with any future debt issuances.

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 ~~this~~their evaluation ~~the~~as of September 30, 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 ~~existence of previously reported~~ material weaknesses ~~as of the end of the period covered by this Quarterly Report on Form 10-Q. The material weaknesses were identified and discussed~~ in ~~“Part~~control over financial reporting previously disclosed in Part II, – Item 9A ~~– Controls and Procedures”~~ of our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016.~~ 2022.

Notwithstanding the identified material weaknesses, management, including our principal executive officer and principal financial officer, believes the unaudited 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 ~~U.S.~~ GAAP.

MANAGEMENT’S PLAN FOR REMEDIATION OF THE MATERIAL ~~WEAKNESSES~~WEAKNESS

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes.

~~Our management conducted an assessment of the effectiveness~~As previously described in Part II, Item 9A of our ~~internal control over financial reporting as of~~Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016. This assessment was based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in~~ ~~Internal Control—Integrated Framework~~ ~~(2013 framework). Based on this assessment, because of the effect of~~2022, we began implementing a remediation plan to address the material weaknesses as described in the following paragraph, management determined that our internal control over financial reporting was not effective as of December 31, 2016. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements could occur butmentioned above. The weaknesses will not be ~~prevented or detected on a timely basis.~~

~~At December 31, 2016, management determined that~~considered remediated until the ~~effectiveness and timeliness of the performance of~~applicable controls related to the review of financial reports, the review of account reconciliations and the evaluation and reporting of significant and unusual transactions was not adequate to ensure that the material weakness in internal control identified in 2015 had been fully remediated. Management also determined that as of December 31, 2016 there was a material weakness related to the execution of the control for the physical count of operational spares (included in the “Equipment and other” line item in the consolidated balance sheet) which is performed annually to validate its existence.

In response to the identified material weaknesses at December 31, 2016, our management, with oversight from our Audit Committee, has taken the following actions to remediate the material weaknesses described above:

~~In addition, management is taking actions to train personnel and improve policies and procedures related to the periodic validation of equipment used in operations.~~

Management is committed to improving our internal control processes and believes that the measures described above should remediate the material weaknesses identified and strengthen internal control over financial reporting. As we continue to evaluate and improve internal control over financial reporting, additional measures to remediate the material weaknesses or modifications to certain of the remediation procedures described above may be necessary. We expect to complete the required remedial actions during the fourth quarter of 2017.

While senior management and our Audit Committee are closely monitoring the implementation of these remediation plans, we cannot provide any assurance that these remediation efforts will be successful or that internal control over financial reporting will be effective as a result of these efforts. Until the remediation steps set forth above are fully implemented and operatingoperate 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 ~~that exist at September 30, 2017~~ will ~~continue~~be completed prior to ~~exist.~~the end of fiscal year 2023.

Except for the activities taken related to the remediation of the material weaknesses described above, there ~~were~~have been no changes in our internal control over financial reporting ~~that occurred~~ during the three months ended September 30, ~~2017~~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 ~~all~~none of the claims and litigation we are currently involved in are ~~not likely~~material to ~~have a material adverse effect on~~ our ~~consolidated financial position, cash flows or results of operations.~~business.

Our business faces many risks. Any of the risks discussed elsewhere in this ~~Form 10-Q~~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 1A1A. “Risk Factors” in our ~~2016~~2022 Form 10-K. There have been no material changes in our risk factors from those described in our ~~2016~~2022 Form 10-K.

There were no sales of unregistered securities during the quarter ended September 30, 2023 that were not previously reported on a Current Report on Form 8-K.

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 up to 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 September 30, 2023:

Subsequent to September 30, 2023 and through November 3, 2023, the following table represents the details of various repurchases under the Plan:

During the three months ended September 30, 2023, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act)

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.


Delaware		~~76‑0274813~~76-0274813
(Stateorotherjurisdictionof ~~Incorporation~~ incorporationororganization)		(I.R.S.Employer IdentificationNo.)

9800RichmondAvenue Suite 700 Houston, Texas		77042
(Addressofprincipalexecutiveoffices)	(Zip code)	~~(Zip code)~~

Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock	EGY	New York Stock Exchange
Common Stock	EGY	London Stock Exchange



PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
September 30, ~~2017~~2023 and December 31, ~~2016~~2022	3 2
Condensed Consolidated Statements of Operations
and Comprehensive Income Three and Nine Months Ended September 30, ~~2017~~2023 and ~~2016~~2022	4 3
Condensed Consolidated Statements of Shareholders’ Equity Three and Nine Months Ended September 30, 2023 and 2022	4
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, ~~2017~~2023 and ~~2016~~2022	5
Notes to Condensed Consolidated Financial Statements (unaudited)	6 7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18 22
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26 37
ITEM 4. CONTROLS AND PROCEDURES	26 38
PART II. OTHER INFORMATION	27 39
ITEM 1. LEGAL PROCEEDINGS	27 39
ITEM 1A. RISK FACTORS	28 39
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 5. OTHER INFORMATION	47
ITEM 6. EXHIBITS	29 41

	*As of September 30, 2023*			*As of December 31, 2022*
	*(in thousands)*
ASSETS
Current assets:
Cash and cash equivalents	$	103,353		$	37,205
Restricted cash		111			222
Receivables:
Trade, net		22,788			52,147
Accounts with joint venture owners, net of allowance for credit losses of $0.6 and $0.3 million, respectively		1,635			15,830
Foreign income taxes receivable		—			2,769
Other, net of allowance for credit losses of $3.5 and $0.0 million, respectively		64,826			68,519
Crude oil inventory		9,287			3,335
Prepayments and other		16,115			20,070
Total current assets		218,115			200,097

Crude oil and natural gas properties, equipment and other - successful efforts method, net		467,877			495,272
Other noncurrent assets:
Restricted cash		1,787			1,763
Value added tax and other receivables, net of allowance of $9.9 million and $8.4 million, respectively		9,462			7,150
Right of use operating lease assets		3,510			2,777
Right of use finance lease assets		87,971			90,698
Deferred tax assets		31,222			35,432
Abandonment funding		6,268			20,586
Other long-term assets		1,616			1,866
Total assets	$	827,828		$	855,641
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	43,924		$	59,886
Accounts with joint venture owners		1,151			—
Accrued liabilities and other		76,470			91,392
Operating lease liabilities - current portion		3,539			2,314
Finance lease liabilities - current portion		7,810			7,811
Foreign income taxes payable		33,256			—
Current liabilities - discontinued operations		673			687
Total current liabilities		166,823			162,090
Asset retirement obligations		45,201			41,695
Operating lease liabilities - net of current portion		82			686
Finance lease liabilities - net of current portion		77,862			78,248
Deferred tax liabilities		76,120			81,223
Other long-term liabilities		17,369			25,594
Total liabilities		383,457			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, 121,341,251 and 119,482,680 shares issued, 105,714,499 and 107,852,857 shares outstanding, respectively		12,134			11,948
Additional paid-in capital		356,424			353,606
Accumulated other comprehensive income		844			1,179
Less treasury stock, 15,626,752 and 11,629,823 shares, respectively, at cost		(65,145	)		(47,652	)
Retained earnings		140,114			147,024
Total shareholders' equity		444,371			466,105
Total liabilities and shareholders' equity	$	827,828		$	855,641


	September 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	18,863	$	20,474
Restricted cash		829		741
Receivables:
Trade		7,203		6,751
Accounts with partners, net of allowance of $0.5 million at September 30, 2017 and December 31, 2016		2,748		3,297
Other		1		120
Crude oil inventory		1,160		913
Prepayments and other		2,952		4,040
Current assets - discontinued operations		2,773		2,139
Total current assets		36,529		38,475
Property and equipment - successful efforts method:
Wells, platforms and other production facilities		389,204		389,231
Undeveloped acreage		10,000		10,000
Equipment and other		10,318		9,779
		409,522		409,010
Accumulated depreciation, depletion, amortization and impairment		(385,617)		(380,991)
Net property and equipment		23,905		28,019
Other noncurrent assets:
Restricted cash		967		918
Value added tax and other receivables, net of allowance of $6.2 million and $4.7 million at September 30, 2017 and December 31, 2016, respectively		6,624		5,110
Abandonment funding		8,510		8,510
Total assets	$	76,535	$	81,032

LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	13,849	$	19,096
Accrued liabilities and other		10,098		10,506
Current portion of long term debt		7,500		7,500
Current liabilities - discontinued operations		15,400		18,452
Total current liabilities		46,847		55,554
Asset retirement obligations		19,202		18,612
Other long term liabilities		284		284
Long term debt, excluding current portion		3,483		6,940
Total liabilities		69,816		81,390
Commitments and contingencies (Note 6)
Shareholders’ equity (deficit):
Preferred stock, none issued, 500,000 shares authorized, $25 par value		—		—
Common stock, 66,382,243 and 66,109,565 shares issued $0.10 par value, 100,000,000 shares authorized		6,638		6,611
Additional paid-in capital		71,106		70,268
Less treasury stock, 7,564,212 and 7,555,095 shares at cost		(37,941)		(37,933)
Accumulated deficit		(33,084)		(39,304)
Total shareholders' equity (deficit)		6,719		(358)
Total liabilities and shareholders' equity (deficit)	$	76,535	$	81,032

	*Three Months Ended September 30,*						*Nine Months Ended September 30,*
	*2023*			*2022*			*2023*			*2022*
	*(in thousands, except per share amounts)*
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	116,269		$	78,097		$	305,912		$	257,738
Operating costs and expenses:
Production expense		39,956			23,312			106,760			67,147
FPSO Demobilization		—			8,867			5,647			8,867
Exploration expense		1,194			56			1,259			250
Depreciation, depletion and amortization		32,538			8,963			94,958			21,827
General and administrative expense		6,216			1,979			16,835			10,507
Credit losses and other		822			1,020			2,437			2,083
Total operating costs and expenses		80,726			44,197			227,896			110,681
Other operating income (expense), net		5			—			(298	)		(5	)
Operating income		35,548			33,900			77,718			147,052
Other income (expense):
Derivative instruments gain (loss), net		(2,320	)		3,778			(2,268	)		(37,522	)
Interest expense, net		(1,426	)		(234	)		(5,375	)		(355	)
Other income (expense), net		183			(7,707	)		(1,494	)		(10,514	)
Total other expense, net		(3,563	)		(4,163	)		(9,137	)		(48,391	)
Income from continuing operations before income taxes		31,985			29,737			68,581			98,661
Income tax expense (benefit)		25,844			22,843			52,203			64,467
Income from continuing operations		6,141			6,894			16,378			34,194
Loss from discontinued operations, net of tax		—			(26	)		(15	)		(58	)
Net income	$	6,141		$	6,868		$	16,363		$	34,136
Other comprehensive income (loss)
Currency translation adjustments		(2,216	)		—			(335	)		—
Comprehensive income	$	3,925		$	6,868		$	16,028		$	34,136

Basic net income per share:
Income from continuing operations	$	0.06		$	0.12		$	0.15		$	0.57
Loss from discontinued operations, net of tax		—			—			—			—
Net income per share	$	0.06		$	0.12		$	0.15		$	0.57
Basic weighted average shares outstanding		106,289			59,068			106,876			58,900
Diluted net income per share:
Income from continuing operations	$	0.06		$	0.11		$	0.15		$	0.57
Loss from discontinued operations, net of tax		—			—			—			—
Net income per share	$	0.06		$	0.11		$	0.15		$	0.57
Diluted weighted average shares outstanding		106,433			59,450			107,072			59,335

	*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		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
Shares issued - stock-based compensation		135		(16	)		13		198			—			—			—			211
Stock-based compensation expense		—		—			—		1,020			—			—			—			1,020
Common Shares Purchased		—		(1,403	)		—		—			—			(6,026	)		—			(6,026	)
Treasury stock		—		—			—		—			—			(64	)		—			(64	)
Dividend Distributions		—		—			—		—			—			—			(6,701	)		(6,701	)
Other comprehensive income		—		—			—		—			(2,216	)		—			—			(2,216	)
Net income		—		—			—		—			—			—			6,141			6,141
Balance at September 30, 2023		121,341		(15,627	)	$	12,134	$	356,424		$	844		$	(65,145	)	$	140,114		$	444,371

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
	*(in thousands)*
Allowance for credit losses and other
Balance at beginning of period	$	(13,519	)	$	(6,389	)	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(822	)		(1,020	)		(2,437	)		(2,083	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—			—			(3,120	)		—
Foreign currency gain (loss)		238			355			158			770
Balance at end of period	$	(14,103	)	$	(7,054	)	$	(14,103	)	$	(7,054	)

		*As of September 30, 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	$	—	$	239	$	—	$	239
Derivative liability	Accrued liabilities and other		—		2,162		—		2,162
		$	—	$	2,401	$	—	$	2,401

`		As of December 31, 2022
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		*(in thousands)*
Assets
Derivative asset	Prepayments and other	$	—	$	102	$	—	$	102
		$	—	$	102	$	—	$	102
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	556	$	—	$	556
		$	—	$	556	$	—	$	556


		~~November 22, 2016~~
		~~(in thousands)~~
~~Assets acquired:~~
~~Wells, platforms and other production facilities~~	$	~~5,754~~
~~Equipment and other~~		~~684~~
~~Value added tax and other receivables~~		~~297~~
~~Abandonment funding~~		~~546~~
~~Accounts receivable - trade~~		~~888~~
~~Prepayments and other~~		~~220~~
~~Liabilities assumed:~~
~~Asset retirement obligations~~		~~(1,731)~~
~~Accrued liabilities and other~~		~~(747)~~
~~Total identifiable net assets and consideration transferred~~	$	~~5,911~~

(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 September 30, 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 acquisition based on the purchase price allocation.
(c)	The unaudited pro forma net income for the three months ended September 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.
(d)	The unaudited pro forma operating income for the nine months ended September 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 acquisition based on the purchase price allocation.
(e)	The unaudited pro forma net income for the nine months ended September 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.

	*Three Months Ended September 30, 2023*
(in thousands)	*Gabon*			*Egypt*			*Canada*		*Equatorial Guinea*			*Corporate and Other*			*Total*
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	57,275		$	50,307		$	8,687	$	—		$	—		$	116,269
Operating costs and expenses:
Production expense		20,731			16,040			2,627		259			299			39,956
FPSO Demobilization		—			—			—		—			—			—
Exploration expense		—			1,194			—		—			—			1,194
Depreciation, depletion and amortization		14,583			12,967			4,948		—			40			32,538
General and administrative expense		348			54			—		94			5,720			6,216
Credit losses and other		684			—			—		138			—			822
Total operating costs and expenses		36,346			30,255			7,575		491			6,059			80,726
Other operating income (expense), net		5			—			—		—			—			5
Operating income		20,934			20,052			1,112		(491	)		(6,059	)		35,548
Other income (expense):
Derivative instruments loss, net		—			—			—		—			(2,320	)		(2,320	)
Interest (expense) income, net		(1,371	)		(270	)		—		—			215			(1,426	)
Other (expense) income, net		111			—			—		(3	)		75			183
Total other expense, net		(1,260	)		(270	)		—		(3	)		(2,030	)		(3,563	)
Income (loss) from continuing operations before income taxes		19,674			19,782			1,112		(494	)		(8,089	)		31,985
Income tax (benefit) expense		13,173			888			—		—			11,783			25,844
Income (loss) from continuing operations		6,501			18,894			1,112		(494	)		(19,872	)		6,141
Loss from discontinued operations, net of tax		—			—			—		—			—			—
Net income (loss)	$	6,501		$	18,894		$	1,112	$	(494	)	$	(19,872	)	$	6,141
Consolidated capital expenditures	$	10,109		$	11,987		$	3,870	$	—		$	—		$	25,966

	*Three Months Ended September 30, 2022*
(in thousands)	*Gabon*			*Equatorial Guinea*			*Corporate and Other*			*Total*
Revenues:
Crude oil and natural gas sales	$	78,097		$	—		$	—		$	78,097
Operating costs and expenses:
Production expense		22,828			484			—			23,312
FPSO demobilization		8,867			—			—			8,867
Exploration expense		56			—			—			56
Depreciation, depletion and amortization		8,940			—			23			8,963
General and administrative expense		915			120			944			1,979
Bad debt expense and other		681			339			—			1,020
Total operating costs and expenses		42,287			943			967			44,197
Other operating income (expense), net		—			—			—			—
Operating income		35,810			(943	)		(967	)		33,900
Other income (expense):
Derivative instruments loss, net		—			—			3,778			3,778
Interest (expense) income, net		(351	)		—			117			(234	)
Other (expense) income, net		(1,305	)		1			(6,403	)		(7,707	)
Total other expense, net		(1,656	)		1			(2,508	)		(4,163	)
Income from continuing operations before income taxes		34,154			(942	)		(3,475	)		29,737
Income tax (benefit) expense		25,415			—			(2,572	)		22,843
Income from continuing operations		8,739			(942	)		(903	)		6,894
Loss from discontinued operations, net of tax		—			—			(26	)		(26	)
Net income	$	8,739		$	(942	)	$	(929	)	$	6,868
Consolidated capital expenditures	$	51,610		$	—		$	53		$	51,663

	*Nine Months Ended September 30, 2022*
(in thousands)	*Gabon*			*Equatorial Guinea*			*Corporate and Other*			*Total*
Revenues:
Crude oil and natural gas sales	$	257,738		$	—		$	—		$	257,738
Operating costs and expenses:
Production expense		66,269			878			—			67,147
FPSO demobilization		8,867			—			—			8,867
Exploration expense		250			—			—			250
Depreciation, depletion and amortization		21,766			—			61			21,827
General and administrative expense		2,073			329			8,105			10,507
Credit losses and other		1,744			339			—			2,083
Total operating costs and expenses		100,969			1,546			8,166			110,681
Other operating income (expense), net		(5	)		—			—			(5	)
Operating income		156,764			(1,546	)		(8,166	)		147,052
Other income (expense):
Derivative instruments loss, net		—			—			(37,522	)		(37,522	)
Interest (expense) income, net		(515	)		—			160			(355	)
Other (expense) income, net		(2,799	)		(1	)		(7,714	)		(10,514	)
Total other expense, net		(3,314	)		(1	)		(45,076	)		(48,391	)
Income from continuing operations before income taxes		153,450			(1,547	)		(53,242	)		98,661
Income tax (benefit) expense		74,671			1			(10,205	)		64,467
Income from continuing operations		78,779			(1,548	)		(43,037	)		34,194
Loss from discontinued operations, net of tax		—			—			(58	)		(58	)
Net income	$	78,779		$	(1,548	)	$	(43,095	)	$	34,136
Consolidated capital expenditures	$	121,492		$	—		$	120		$	121,612

Settlement Period	*Type of Contract*	*Index*	*Average Monthly Volumes*		*Weighted Average Put Price*		*Weighted Average Call Price*
			(Bbls)		(per Bbl)		(per Bbl)
October 2023 - December 2023	Collars	Dated Brent		85,000	$	65.00	$	90.00
January 2024 - March 2024	Collars	Dated Brent		85,000	$	65.00	$	97.00
April 2024 - June 2024	Collars	Dated Brent		65,000	$	65.00	$	100.00

		*Three Months Ended September 30,*						*Nine Months Ended September 30,*
Derivative Item	*Statements of Operations Line*	*2023*			*2022*			*2023*			*2022*
		*(in thousands)*						*(in thousands)*
Commodity derivatives	Cash settlements paid on matured derivative contracts, net	$	1		$	(9,124	)	$	(62	)	$	(42,683	)
	Unrealized gain (loss)		(2,321	)		12,902			(2,206	)		5,161
	Derivative instruments gain (loss), net	$	(2,320	)	$	3,778		$	(2,268	)	$	(37,522	)

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*
July 1, 2023 - July 31, 2023		505,720	$	3.96		505,720	$	15,504,180
August 1, 2023 - August 31, 2023		435,342	$	4.61		435,342	$	13,505,242
September 1, 2023 - September 30, 2023		462,300	$	4.31		462,300	$	11,514,870
Total		1,403,362				1,403,362

	*Operating Leases*		*Finance Leases*
Year	*(in thousands)*
2023	$	1,257	$	3,632
2024		2,464		14,448
2025		32		16,202
2026		—		16,443
2027		—		15,023
Thereafter		—		51,562
		3,753		117,310
Less: imputed interest		132		31,638
Total lease liabilities	$	3,621	$	85,672


		Carrying		Fair Value Measurements Using
Derivative Item	Balance Sheet Line	Value		Level 1		Level 2		Level 3
		(in thousands)
Crude oil puts	Prepayments and other
Balance at September 30, 2017		$	61	$	—	$	61	$	—
Balance at December 31, 2016		$	1,227	$	—	$	1,227	$	—


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share
	(in thousands)
Outstanding at January 1, 2017	2,644	$	3.92
Granted	1,550		0.99
Exercised	(37)		1.04
Forfeited/expired	(1,202)		4.63
Outstanding at September 30, 2017	2,955		2.13


	Restricted Stock	Weighted Average Grant Price
	(in thousands)
Non-vested shares outstanding at January 1, 2017	252	$	1.31
Awards granted	386		0.98
Awards vested	(235)		1.12
Awards forfeited	(41)		1.00
Non-vested shares outstanding at September 30, 2017	362		1.12


	Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share
	(in thousands)
Outstanding at January 1, 2017	180	$	1.04
Granted	1,050		1.20
Forfeited/expired	(153)		1.20
Outstanding at September 30, 2017	1,077		1.17

	*Currency Translation Adjustments*
	*(in thousands)*
Balance at December 31, 2022	$	1,179
Other comprehensive income (loss) before reclassifications		(125	)
Balance at March 31, 2023	$	1,054
Other comprehensive income (loss) before reclassifications		2,006
Balance at June 30, 2023	$	3,060
Other comprehensive income (loss) before reclassifications		(2,216	)
Balance at September 30, 2023	$	844



	Three Months Ended September 30, 2017
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	18,162	$	—	$	16	$	—	$	18,178
Depreciation, depletion and amortization		1,633		—		—		67		1,700
Bad debt expense and other		(49)		—		—		—		(49)
Operating income (loss)		6,067		(44)		10		(2,312)		3,721
Interest expense, net		(327)		—		—		—		(327)
Income tax expense		2,749		—		—		—		2,749
Additions to property and equipment - accrual		237		—		—		60		297


	Three Months Ended September 30, 2016
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	14,540	$	—	$	95	$	—	$	14,635
Depreciation, depletion and amortization		1,508		—		38		61		1,607
Impairment of proved properties		—		—		88		—		88
Bad debt expense and other		63		—		—		—		63
Other operating expense		324		—		—		—		324
Operating income (loss)		5,013		(184)		(61)		(1,078)		3,690
Interest income (expense), net		(329)		—		—		2		(327)
Income tax expense (benefit)		2,305		—		—		(107)		2,198
Additions to property and equipment - accrual		674		—		—		7		681


	Nine Months Ended September 30, 2017
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	59,823	$	—	$	46	$	—	$	59,869
Depreciation, depletion and amortization		5,344		—		1		194		5,539
Bad debt expense and other		232		—		—		—		232
Operating income (loss)		25,117		(97)		356		(7,920)		17,456
Interest expense, net		(1,108)		—		—		—		(1,108)
Income tax expense		9,039		—		—		—		9,039
Additions to property and equipment - accrual		1,051		—		—		60		1,111


	Nine Months Ended September 30, 2016
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	44,212	$	—	$	246	$	-	$	44,458
Depreciation, depletion and amortization		5,484		—		121		182		5,787
Impairment of proved properties		—		—		88		—		88
Bad debt expense and other		577		—		—		—		577
Other operating expense		9,959		—		—		—		9,959
Operating income (loss)		1,481		(319)		(64)		(6,308)		(5,210)
Interest expense, net		(2,285)		—		—		—		(2,285)
Income tax expense		6,884		—		—		—		6,884
Additions to property and equipment - accrual		(1,819)		—		140		7		(1,672)

*(in thousands)*
Price	$	(226,453	)
Volume		276,885
Other		(2,258	)
	$	48,174

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
July 1, 2023 - July 31, 2023		505,720	$	3.96		505,720	$	15,504,180
August 1, 2023 - August 31, 2023		435,342	$	4.61		435,342	$	13,505,242
September 1, 2023 - September 30, 2023		462,300	$	4.31		462,300	$	11,514,870
Total		1,403,362				1,403,362


3.1	Restated Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014 and incorporated herein by reference).
~~3.2~~3.1.1	~~Second Amended and~~Certificate of Amendment to Restated ~~Bylaws~~Certificate of Incorporation of VAALCO, dated October 13, 2022 (filed as Exhibit ~~3.2~~3.1 to the Company’s Current Report on Form 8-K filed on ~~September 28, 2015,~~October 13, 2022 and incorporated herein by reference).
~~3.3~~3.2	~~First Amendment to the Second~~Third Amended and Restated Bylaws, dated July 30, 2020 (filed as Exhibit 3.1 to the ~~Company’s~~Company’s Current Report on Form 8-K filed on August 4, 2020 and incorporated herein by reference).
3.3	Certificate of Elimination of Series A Junior Participating Preferred Stock of VAALCO Energy, Inc., dated as of December 22, 2015 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
~~31.1~~31.1(a)~~(a)~~	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
~~31.2~~31.2(a)~~(a)~~	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
~~32.1~~32.1(b)~~(b)~~	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
~~32.2~~32.2(b)~~(b)~~	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	Inline XBRL Instance Document.
101.SCH(a)	Inline XBRL Taxonomy Schema Document.
101.CAL(a)	Inline XBRL Calculation Linkbase Document.
101.DEF(a)	Inline XBRL Definition Linkbase Document.
101.LAB(a)	Inline XBRL Label Linkbase Document.
101.PRE(a)	Inline XBRL Presentation Linkbase Document.
104	Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).


By	:	/s/ ~~Philip F. Patman, Jr.~~Ronald Bain
		Ronald Bain
		~~Philip F. Patman, Jr.~~
		Chief Financial Officer (~~on behalf of the Registrant)~~Principal Financial Officer)

~~(in thousands)~~

~~Volume~~