Vaalco Energy Inc: Form 10-Q for the period ended Sep 30, 2023

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

• volatility of, and declines and weaknesses in crude oil, natural gas and NGLs prices, as well as our ability to offset volatility in prices through the use of hedging transactions;
• our ability to remediate our 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 maintain sufficient liquidity in order to fully implement our business plan;
• our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;
• the ability of the BWE Consortium to successfully execute its business plan;
• our ability to attract capital or obtain debt financing arrangements;
• our ability to pay the expenditures required in order to develop certain of our 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;
• 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 credit;
• our ability to enter into new customer contracts;
• changes in customer demand and producers’ supply;
• actions by the governments and other significant actors with respect to events occurring in the countries in which we operate;
• actions by our joint venture 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;
• the outcome of any governmental audit; and
• actions of operators of our crude oil, natural gas and NGLs properties.

The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the 2022 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.

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

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

INTRODUCTION

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

RECENT DEVELOPMENTS

Dividend Policy

On February 14, 2023, our board of directors increased our quarterly cash dividend policy to an expected $0.0625 per common share per quarter, commencing in the first quarter of 2023. 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 fourth quarter of 2022. We are currently evaluating locations and planning for the next drilling campaign at Etame that is expected to occur in 2024. In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) and related field reconfiguration processes. This project provides a low cost FSO solution that increases the storage capacity for the Etame block 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.

At the end of September 2023, all wells were online from the end of 2022 as the gas lift compression system was successfully commissioned. This gas lift compression system increased the production and the reliability of two subsea wells, positively impacting our volumes for the 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 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 cost effective flow assurance program. Continued optimization and understanding of the post reconfiguration process dynamics of the Etame platform, have maintained a very high uptime availability of Etame Facility and 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 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 steady state operation following project completion. Equipment reliability and availability remain at high levels. The actual percentages of 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.

Egypt

We continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed six wells in the third quarter of 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 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 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

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.

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 total depth of 22,024 feet. The second well of the program, 16-30-29-3W5, was spudded on February 22, 2023, and drilled to a total depth of 14,446 feet. The 2 wells were completed between late March and early April and 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 May with cycle times that were significantly less than historical cycle times. The wells flowed in the months of May and June. In early July the pump and rods were run on both wells. Both wells continue to produce and both wells continued to exceed expectations during the third quarter of 2023.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame Marin Block on behalf of a consortium of companies. As of September 30, 2023, production operations in the Etame Marin block included fifteen platform wells, plus two subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery and processing at the Etame platform. From the Etame platform, the crude oil is pumped through a riser system to the FSO where it is stored and ultimately offloaded. The leased FSO is anchored to the seabed on the block. The Etame field currently has a combined total of seventeen producing wells. During the three months ended September 30, 2023 and 2022, production 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 Operations”. During the nine months ended September 30, 2023 and 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 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, 2023, production from the Eastern Desert was 3,032 MBbls (2,074 MBbls, net).

The SGZ-6X well in the South Ghazalat concession in the Western Desert is currently suspended pending further evaluation.

Canada

In Harmattan, Canada, we own production and working interests in the Cardium light oil and Mannville liquids-rich gas assets. This property produces oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 2,000 to 2,600 meters. All gas is delivered to a third party non-operated gas plant for processing. During the three months ended September 30, 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 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 undeveloped leasehold costs associated with the Block P license. In February of 2023, we acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.8 million at first commercial production of the Block. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus development plan has been initiated. VAALCO, as operator, is in the process of working through the project charter and timing of key milestones. In addition, 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 for the area associated with the Venus development. The PSC also includes the portions of Block P not associated with the Block P - Venus development.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

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

(in thousands)

The $21.5 million increase in net cash provided by 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, 2023 compared to the same period of 2022 was primarily related to 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 decrease in net cash used in investing activities during the nine months ended September 30, 2023 was due to capital spending costs associated with the development drilling programs in Egypt and Canada not exceeding prior year expenditures along with reduced current year expenditures for Gabon. For the nine months ended September 30, 2022, cash used in investing activities was due to increases in capital spending in 2022 for 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 used in financing activities during the nine months ended September 30, 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 had accrual basis capital expenditures attributable to continuing operations of $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, 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.

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 receive for our crude oil, natural gas and NGLs significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Crude oil and natural gas commodities and, therefore their prices can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future.

Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps and costless collars to hedge price risk associated with a portion of our anticipated crude oil production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the unaudited condensed consolidated statements of operations and comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheet.

Cash on Hand

At September 30, 2023, we had unrestricted cash of $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 block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

We currently sell all our crude oil production from Gabon under a COSMA with Glencore. Under the COSMA all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the Final Maturity Date of the Facility, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Revenues associated with the sales of our crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, we record the EGPC’s share of production as royalties which are netted against revenue. With respect to taxes in Egypt, our income taxes under the terms of the Merged Concession Agreement are the liability of TransGlobe Petroleum International ("TGPI"), a wholly-owned indirect subsidiary of VAALCO. TGPI's income taxes are paid by EGPC on behalf of TGPI out of EGPC’s production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of TGPI are recognized as oil and gas sales revenue and income tax expense for reporting purposes.

For the 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.

Capital Resources, Liquidity and Cash Requirements

Historically, our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. 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 required to pay an additional $10.0 million on February 1 for each of the next three years. In addition, we have committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (totaling $150.0 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which is subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.

RBL Facility Agreement and Available Credit

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 our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base. The 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 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. 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 is was replaced due to concerns about the sustainability of LIBOR as a global reference rate.

We were in compliance with the financial covenants contained in the Facility at September 30, 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.

Abandonment Funding – Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, a new abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis. The new abandonment estimate has been presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. At 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 drilling activities has lengthened, leading to delays and, in most cases, prices for materials have increased.

The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The ongoing conflict has caused, and could intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

Further, the slowdown in the Chinese economy is negatively impacting the global market and the global supply chain problems may have a material adverse impact on our financial results and business operations, including our timing and ability to complete future drilling campaigns and other efforts required to advance the development of our crude oil, natural gas and NGLs properties.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+. However, the Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives.

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 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 in the process of developing a multi-year plan to establish and document our progress in achieving goals we set for ourselves across all areas of sustainability. Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.

CRITICAL ACCOUNTING POLICIES

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

NEW ACCOUNTING STANDARDS

See Note 2 to the Financial Statements.

RESULTS OF OPERATIONS

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

Net income for the three months ended September 30, 2023 was $ 6.1 million compared to net income of $ 6.9 million for the same period of 2022. See discussion below for changes in revenue and expense.

Crude oil, natural gas and NGL revenues increased $38.2 million, or approximately 49%, to $ 116.3 million during the three months ended September 30, 2023 from $ 78.1 million for the same period in the prior year. The revenue increase is attributable to higher volumes sold in Gabon and the addition of the Egypt and Canada segments acquired in the TransGlobe acquisition, partially offset by significantly lower realized sales prices compared to the prior period.

(in thousands except per Boe information)

31

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

(in thousands)

(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.

*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

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $ 57.3 million of revenue to the Company’s total revenue during the three months ended September 30, 2023. This compares to the $ 78.1 million of revenue contributed by the Segment during the three months ended September 30, 2022. The total barrels lifted in Gabon for the three months ended September 30, 2023 was slightly lower than the three months ended September 2022, mainly due to three lifting occurring in the 2022 period compared to two lifting in the 2023 period. This was compounded by the Gabon per barrel price received during the three months ended September 30, 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.

Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the three months ended September 30, 2023, the oil sold in Egypt was through direct sales to EGPC and to Mercuria Energy. The Company’s Egypt segment contribute d $50.3 million of revenue to the Company’s total revenue for the quarter. At September 30, 2023, the Company’s Egypt segment had zero barrels in oil inventory. Since the Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended September 30, 2022.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $ 8.7 million of revenue to the Company’s total revenue for the quarter. Since the Company acquired its Canadian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended September 30, 2022.

Production expenses increased $16.6 million, or approximately 71%, for the three months ended September 30, 2023 to $ 40.0 million from $ 23.3 million for the same period in the prior year. The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to the completed 2021/2022 drilling campaign. VAALCO has seen inflationary pressure on personnel and contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended September 30, 2023 decreased to $ 22.04 per barrel from $31.80 per barrel for the three months ended September 30, 2022 primarily as a result of higher sales volumes for the current period. For both the three months ended September 30, 2023 and 2022, respectively, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic. For the three months ended September 30, 2023 the costs associated with proactive measures related to COVID were not material. For the three months ended September 30, 2022, we incurred $0.2 million in additional costs related to the proactive measures taken in response to the pandemic.

FPSO Demobilization for the three months ended September 30, 2023 was zero. For the three months ended September 30, 2022 , the Company recorded $8.9 million in decommissioning fees, which was reported as a separate line item on the income statement. These 2022 costs were incurred to retire the FPSO as we transitioned the block to the FSO.

Exploration expense for the three months ended September 30, 2023 was $1.2 million due 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 $23.6 million, or approximately 263% for the three months ended September 30, 2023 to $ 32.5 million from $ 9.0 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense 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 acquired 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 $4.2 million, or 214% for the three months ended September 30, 2023 to $ 6.2 million from $ 2.0 million for the same period in the prior year. The increase in general and administrative expenses is primarily due to higher corporate stock based compensation, professional service fees, salaries and wages, and accounting and legal fees.

Credit losses and other decreased by $0.2 million to $0.8 million for the three months ended September 30, 2023 from $1.0 million for the three 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. For the three 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 VAT and therefore request reimbursement from the State of Gabon for VAT for amounts we have paid. Due to the late reimbursement nature of the VAT receivable by the State of Gabon, the Company established an allowance against the receivable. The allowance related to the VAT receivable was $8.4 million on December 31, 2022. For the three months ended September 30, 2023 we added $0.4 million to the allowance account for the current quarter'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 three 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 gain (loss) decreased by $6.1 million, or approximately 161% to a loss of $2.3 million for the three months ended September 30, 2023 from a gain of $3.8 million during the same period in the prior year. Derivative gains for the three months ended September 30, 2022 are a result of the decrease in the price of Dated Brent crude oil below the initial strike price per barrel of the option over the three months ended September 30, 2022. Derivative losses for the three months ended September 30, 2023 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the three months ended September 30, 2023. Our derivative instruments currently cover a portion of our production through June 2024.

Interest expense, net was $1.4 million for the three months ended September 30, 2023 compared to an expense of $0.2 million during the same period in 2022. The increase of net interest expense for the three 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 increased by $7.9 million to an income of $0.2 million for the three months ended September 30, 2023 from an expense of $7.7 million for the three months ended September 30, 2022 . Other (expense) income, net normally consists of foreign currency gains and losses . However, during the three months ended September 30, 2022 there was $6.4 million of transactions costs associated with the TransGlobe acquisition in addition to the foreign currency losses. No such expenses existed during the third quarter of 2023.

Income tax expense (benefit) for the three months ended September 30, 2023 was an expense of $ 25.8 million. This is comprised of current tax expense of $ 26.8 million and $1.0 million of deferred tax benefit. Income tax expense (benefit) for the three months ended September 30, 2022 was an expense of $ 22.8 million. This is comprised of current tax benefit of $1.2 million and $ 24.0 million of deferred tax expense.

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

Net income for the nine months ended September 30, 2023 was $16.4 million compared to net income of $34.1 million for the same period of 2022. See discussion below for changes in revenue and expense.

Crude oil, natural gas and NGLs revenues increased $48.2 million, or approximately 19%, to $305.9 million during the nine months ended September 30, 2023 from $257.7 million for the same period in the prior year. The revenue increase is attributable to the addition of the Egypt and Canada segments acquired in the TransGlobe acquisition, partially offset by lower realized sales prices.

(in thousands except per Boe information)

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

(in thousands)

(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.

*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.

Gabon

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $171.9 million of revenue to the Company’s total revenue during the nine 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, 2023 was less than the barrels lifted during the same period in 2022, mainly due to the timing of liftings. In addition, the Gabon per barrel price received during the nine months ended September 30, 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.

Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the nine months ended September 30, 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 Company’s total revenue for the nine months ended September 30, 2023. At September 30, 2023, the Company’s Egypt segment had zero barrels in oil inventory. Since the Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the nine months ended September 30, 2022.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $27.6 million of revenue to the Company’s total revenue for the nine months ended September 30, 2023. Since the Company acquired its Canadian segment in the fourth quarter of 2022, there are no comparable revenues for the nine months ended September 30, 2022.

Production expenses increased $39.6 million, or approximately 59%, for the nine months ended September 30, 2023 to $106.8 million from $67.1 million for the same period in the prior year. The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to the added production from the now completed 2021/2022 drilling campaign. VAALCO has seen inflationary pressure on personnel and contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the nine months ended September 30, 2023 decreased to $22.32 per barrel from $29.10 per barrel for the nine months ended September 30, 2022 primarily as a result of higher sales volumes. For the nine months ended September 30, 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 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 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 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 (losses). However, the nine months ended September 30, 2023, also included $1.4 million 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 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.

MARKET RISK

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

FOREIGN EXCHANGE RISK

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2023, we had 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 $38.8 million, respectively, (net to VAALCO), denominated in XAF.

Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. We estimate that a 10% decrease in the value of the Canadian dollar against the US dollar would increase the value of the net assets for the nine months ended September 30, 2023 by approximately $0.5 million. Conversely, a 10% increase in the value of the Canadian dollar against the US dollar would decrease the value of the net assets for the 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, 2023, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase the cash value for the nine months ended September 30, 2023 by $0.8 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the nine months ended September 30, 2023 by $0.6 million.

COUNTERPARTY RISK

We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparty. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

COMMODITY PRICE RISK

Our major market risk exposure continues to be the prices received for our crude oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low crude oil and natural gas prices or a resumption of the decreases in crude oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.

With respect to our crude oil sales in Gabon, the price received is based on Dated Brent prices plus or minus a differential. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 665 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.3 million decrease per quarter in revenues and operating income (loss) and a $3.0 million decrease per quarter in net income (loss).

Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between VAALCO’s recognition of costs and their recovery as VAALCO accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, our share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically, maximum cost oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically, the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil.

With respect to our crude oil and NGL sales in Canada, the prices received is based on NYMEX WTI (west Texas Intermediate) prices plus or minus a differential. Natural gas sales are based on Canadian index price that whose price is based, in part. on the NYMEX Henry Hub Natural Gas futures contracts. If Canadian BOE sales were to remain constant at the most recent quarterly sales volumes of 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, 2023, we had unexpired derivative instruments outstanding covering approximately 705 MBbls of production through June 30, 2024. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes. See Note 8 to the Financial Statements for further discussion.

Interest Rate RISK

Changes in market interest rates affect the amount of interest owed on outstanding balances under our Facility. However, as of September 30, 2023 we had no amounts drawn under the facility. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. Additionally, changes in market interest rates could impact interest costs associated with any future debt issuances.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of 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 material weaknesses in control over financial reporting previously disclosed in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

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

MANAGEMENT’S PLAN FOR REMEDIATION OF THE MATERIAL WEAKNESS

As previously described in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, we began implementing a remediation plan to address the material weaknesses mentioned above. The weaknesses will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expect that the remediation of the material weaknesses will be completed prior to the end of fiscal year 2023.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Except for the activities taken related to the remediation of the material weaknesses described above, there have been no changes in our internal control over financial reporting during the three months ended September 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2022 Form 10-K. There have been no material changes in our risk factors from those described in our 2022 Form 10-K.