What changed in VAALCO ENERGY INC /DE/'s 10-K — 2022 vs 2023

Item 1. Business – Segment and Geographical Information – “ Gabon Segment ”, " Egypt Segment", " Canada Segment", and “ Equatorial Guinea Segment ”" . We own a working interest in, and are the operator of, the Etame PSC related to the Etame Marin block located offshore Gabon in West Africa.

The Etame Marin block covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet. Currently, our working interest in the Etame Marin block is 58.8%, and we are designated as the operator on behalf of the Etame Consortium.

The block is subject to a 7.5% back-in carried interest by the government of Gabon, which they have assigned to a third party. Our working interest will decrease to 57.2% in June 2026 when the back-in carried interest increases to 10%. We are also a member of a consortium with BW Energy and Panoro Energy (the “BWE Consortium”).

The BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. Negotiations to finalize the commercial terms were held in 2023, however, they were halted late in the year due to the presidential elections. The next step is concluding the terms of PSCs with the Gabonese government.

The negotiations were kick started again at the request of the Gabonese Government in early February 2024, where the consortium and the government came to an agreement on the fiscal terms on February 9, 2024. The next step is concluding the terms of the PSC with the Gabonese government.

BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (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.

As a result of the Arrangement with TransGlobe in 2022, we own a 100% working interest in PSCs covering two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions (45,067 acres) and the Western Desert which contains the South Ghazalat concession (7,340 acres).

We also acquired TransGlobe’s production and working interests in Cardium light oil and Mannville liquids-rich gas assets located in Harmattan, Canada (47,400 gross acers developed). See Note 4 to the consolidated financial statements for further discussion regarding the Arrangement. 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 late 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 2024 to minimize decline until the next drilling campaign.

At the end of December 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 year ended December 31, 2023.

Gas lift compression and subsea wells remained online with a high level of reliability through the year ended December 31, 2023. The focus during the beginning 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 fourth 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. 49 Table of Contents Charter Agreement for the Floating Storage and Offloading Unit in Gabon In August of 2021, we and our co-venturers at Etame approved the FSO Agreements with World Carrier to replace the existing FPSO with an FSO.

The FSO Agreements required a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net to VAALCO) in 2022 of which $6 million will be recovered against future rentals.

On October 19, 2022, the replacement of the existing FPSO was completed and we signed the final acceptance certificate, at which time control of the FSO vessel transferred to us. The new FSO has been named “Teli” (renamed from “Cap Diamant”) and is on site and accepting oil at the Etame Marin block.

Total field conversion expenses were $122 million gross ($77 million net to VAALCO).

The FPSO charter we were party to prior to the FSO installation was set to expire in September 2022, but on September 9, 2022 we signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022, and ratified certain decommissioning and demobilization items associated with exiting the contract.

Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022 and other demobilization fees totaling $15.3 million on a gross basis ($8.9 million net to VAALCO). The demobilization of the FPSO was carried out from October 5, 2022 through to November 19, 2023.

This included the cleaning and removal of waste from the Cargo and Slop Tanks. In the fourth quarter of 2023, the joint operating group in Gabon reached a settlement agreement with Tinworth to release the joint operating group from any further obligation pertaining to the former FPSO.

The signed agreement, dated December 12, 2023, called for the group to pay an additional $8 million gross ($4.7 million net to VAALCO) to Tinworth in exchange for the release. The payment was made on December 22, 2023.

Based on this and the prior expense incurred earlier in the year, VAALCO reported $7.5 million in FPSO Demobilization costs on the income statement for the year ended December 31, 2023. The sail date on the FPSO was November 19, 2023. Egypt VAALCO continued to use the EDC-64 rig in the Eastern Desert drilling campaign.

We continue to drill an average of two wells per month with the EDC-64 rig and we drilled 18 wells in year 2023. The SGZ-6X well remains shut-in. We continue to evaluate our strategic options. There was no production from South Ghazalat due to the SGZ-6X remaining shut-in.

There is a planned workover for this well in 2024 to resume production.

A summary of the Egyptian drilling campaign's impact during 2023 is presented below: VAALCO Egypt 2023 Wells Well Spud date Net Pay (ft) Penetrated Pay Zones Completion Zone Perforation Interval (ft) IP-30 Rate (BOPD) EastArta-53 1/15/2023 14.8 Redbed Redbed Hydraulic Frac 35 K-81 2/2/2023 68.9 Asl-D and E Asl-E 13.1 255 K-79 2/21/2023 190 Asl-A, B, D, E and F Asl-B1 and B2 59 150 Arta-80 3/10/2023 33 Redbed Redbed 32 440 Arta-81 3/21/2023 28.5 Redbed Redbed 26 340 HE-4 4/2/2023 27.9 Asl-B1 and B2 Asl-B2 13.1 440 HE-5 Injector 4/16/2023 4.9 Asl-B2 Asl-B2 9.8 NA HE-3 5/10/2023 9.2 Asl-B1 and B2 Asl-B2 16.4 235 Arta-82 5/25/2023 42 Redbed Redbed 28 150 Arta-84 6/6/2023 34 Nukhul Nukhul Hydraulic Frac 68 NWG-5C1 6/16/2023 none Nukhul Temporarily Abandoned none none K-80 6/30/2023 141.4 Asl-A, B, D and E Asl-E 16.4 144 K-84 7/16/2023 98.8 Asl-D, E, F and G Asl-G2 19.7 125 K-85 7/31/2023 63.3 Asl-D, E, F and G Asl-E 9.8 82 M-24 8/14/2023 70.2 Asl-A, B and D Asl-D 9.8 134 Arta-91 9/1/2023 40 Nukhul and Redbed Redbed 20 150 EA-54 9/12/2023 none Nukhul, Thebes and Redbed Plugged & Abandoned none none EA-55 10/4/2023 42 Redbed Redbed Hydraulic Frac Pending Frac 50 Table of Contents 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 two 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 free 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 fourth quarter of 2023.

The negotiations were kick started again at the request of the Gabonese Government in early February 2024, where the consortium and the government came to an agreement on the fiscal terms on February 9, 2024. The next step is concluding the terms of the production sharing contracts with the Gabonese government.

The proposed acquisition of Svenska may not be consummated and if consummated, we may not realize the anticipated benefits expected from the acquisition.

On February 29, 2024, Buyer and Seller, entered into the Share Purchase Agreement pursuant to which the Buyer will purchase all of the issued shares in the capital of Svenska for $66.5 million in cash, subject to adjustment as described in the Share Purchase Agreement.

Pursuant to the terms and subject to the conditions of the Share Purchase Agreement, upon Closing, Buyer will acquire Svenska and, as a result, Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa.

Buyer will also acquire a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.

The Purchase Price will be funded by a combination of a dividend of cash on Svenska’s balance sheet to the Seller immediately prior to the consummation of the Acquisition and a portion of VAALCO’s cash-on-hand.

VAALCO estimates that cash due from VAALCO at Closing will be in the range of approximately $30 to $40 million. 29 Table of Contents Closing is subject to obtaining necessarily regulatory approvals in Cote d’Ivoire and Sweden and the satisfaction of other customary closing conditions.

If the closing conditions are not satisfied or waived within nine months of date of the Share Purchase Agreement, then either the Buyer or the Seller may, at its discretion, terminate the Share Purchase Agreement.

No assurance can be given that the required approvals will be obtained or that the required conditions to closing will be satisfied or waived in a timely manner or at all, and accordingly consummation of the Acquisition may be delayed or not occur at all.

If consummated, the success of the Acquisition will depend, in part, on our ability to realize the anticipated benefits from combining our business with Svenska’s business.

The anticipated benefits and efficiencies of the Acquisition may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that we do not currently foresee.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves, including many factors beyond our control.

Future changes to the anticipated abandonment cost estimates could change our asset retirement obligations and increase the amount of future abandonment funding payments we are obligated to make.

In Egypt, under model concession agreements and the Egyptian Fuel Materials Law No. 66/1953 as amended and its Executive Regulations issued by Minister of Industry Decree No. 758/1972 as amended (the “Fuel Materials Law”), liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process.

The model concession agreements do not deal with area handover and abandonment upon termination, expiration or withdrawal from a concession agreement and certain articles in the Fuel Materials Law may apply, albeit the matter in practice is within the discretion of the EGPC.

While the current risk that we may become liable for decommissioning liabilities in Egypt is low, future changes to legislation or practice of the EGPC could result in decommissioning, abandonment and/or handover liabilities in Egypt.

Any increase in Egyptian decommissioning liabilities could adversely affect our financial condition. 30 Table of Contents In relation to petroleum wells, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC.

If EGPC agrees that a producing well is not economic, then the contractor will be responsible for decommissioning the well under an EGPC-approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes.

As EGPC has discretion on decommissioning wells, there is a risk that we could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism.

In Canada, liabilities in respect of the decommissioning of our wells, fields and related infrastructure are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and require us to make provisions for and/or underwrite the liabilities relating to such decommissioning.

It is difficult to accurately forecast the costs that we would incur in satisfying any decommissioning obligations. When such decommissioning liabilities crystallize, we will be liable either on our own or jointly and severally liable with any other former or current partners in the field.

In the event that we are jointly and severally liable with other partners and such partners default on their obligations, we would remain liable, and our decommissioning liabilities could be magnified significantly through such default. Any significant increase in the actual or estimated decommissioning costs that we incur may adversely affect our financial condition.

Under the Alberta LMF, the AER began to set annual mandatory closure spend targets for all licensees with inactive inventory in 2022.

Under the AER’s Closure Nomination Program, introduced in February 2023 through an update to AER Directive 088: Licensee Life-Cycle Management, eligible landowners or land rights holders can nominate oil and gas wells and facilities that have been inactive or abandoned for longer than five years, for closure, at the expense of the licensee.

Liability management in the Alberta oil and gas sector will continue to evolve as the AER continues its phased implementation of the new LMF. If we are required to expend greater amounts than expected on abandoning or decommissioning costs, this could materially affect our revenues and financial performance.

We may not generate sufficient cash to satisfy our payment obligations under the Merged Concession Agreement or be able to collect some or all of our receivables from the EGPC, which could negatively affect our operating results and financial condition.

On January 19, 2022, subsidiaries of TransGlobe executed the Merged Concession Agreement with the EGPC, which is effective upon the Merged Concession Effective Date. Under the Merged Concession Agreement, VAALCO is obligated to make modernization payments that total $65 million and are payable over six years from the Merged Concession Effective Date of which $45.0 million have been paid.

Under the Merged Concession Agreement, TransGlobe will be required to pay an additional $10 million on February 1st for each of the next two years. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024 payments and issue two $10.0 million credits against receivables owed from EGPC.

In addition, VAALCO has also committed to spending a minimum of $50 million over each five-year period for the 15 years of the primary term (total $150 million).

Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which would be subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.

We may be unable to maintain a level of cash flow sufficient to permit us to satisfy the payment obligations under the Merged Concession Agreement. If we are unable to satisfy our obligations, it is possible that the EGPC could seek to terminate the Merged Concession Agreement, which would negatively affect our operating results and financial condition.

In addition, as of the Merged Concession Effective Date, there was an adjustment of funds owed to us for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date. The cumulative amount of the effective date adjustment was estimated at $67.5 million.

However, the cumulative amount of the effective date adjustment is currently being finalized with EGPC and could result in a range of outcomes based on the final price per barrel negotiated. At December 31, 2023, the remaining $50.3 million is recorded on our consolidated balance sheet in Receivables-Other, net.

If the EGPC’s financial position becomes impaired or it disputes or if the EGPC refuses to pay some or all of the said amount, our ability to fully collect such receivable from the EGPC could be impaired, which could negatively affect our operating results and financial condition.

The Egyptian PSCs contain assignment provisions which, if triggered, could adversely affect our business. On October 13, 2022, VAALCO completed its business combination transaction with TransGlobe whereby TransGlobe became an indirect wholly-owned subsidiary of VAALCO.

Legacy subsidiaries of TransGlobe are party to the Egyptian PSCs, which contain restrictive wording relating to assignments of rights under such agreements which, if triggered, require consent of the Egyptian Government in connection with any such assignment (the “Assignment Provisions”).

If triggered, the Assignment Provisions also provide that (i) in certain circumstances, the EGPC has the right to acquire the interest intended to be assigned; and (ii) an assignment fee is payable to the EGPC in an amount equal to 10% of the value of each assignment. We do not believe the Arrangement triggered the Assignment Provisions.

EGPC has not concurred that no assignment fee is payable. We are continuing to engage in discussions with the office of the Minister of Petroleum and Mineral Resources and the EGPC for the purpose of resolving the matter.

Resolution of this matter could result in a range of outcomes and no assurance can be given that such outcomes will not involve an offset of amounts owed by EGPC to VAALCO.

If the Arrangement is deemed to have triggered the Assignment Provisions or VAALCO agrees to make payment to EGPC as part of a resolution, such payment could have an adverse effect on the value of our assets and could adversely affect our results of operations or financial condition.

We could lose our interest in Block P in Equatorial Guinea if we do not meet our commitments under the production sharing contract. Our Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

We and our Block P joint venture owners are evaluating the timing and budgeting for development and exploration activities in the block.

We have completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P and on July 15, 2022 submitted to the EG MMH a plan of development for Block P which on September 16, 2022 was approved by the government of Equatorial Guinea.

Due to delays by the partners in agreeing on certain terms relating to joint operations, the EG MMH delayed commencement of the Plan of Development, but on August 24, 2023, the EG MMH directed that activities relating to the Plan of Development resume.

There can be no certainty any such transaction will be completed or that we will be able to commence drilling operations in Block P.

If the joint venture owners of Block P fail to meet the commitments under the production sharing contract amendment, our capitalized costs of $10 million associated with Block P interest would be impaired. 31 Table of Contents Commodity derivative transactions that we enter into may fail to protect us from declines in commodity prices and could result in financial losses or reduce our income.

In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil, natural gas and NGLs we have entered into and may continue to enter into derivative arrangements with respect to a portion of our expected production.

Our derivative contracts typically consist of a series of commodity swap contracts, such as puts, collars and fixed price swaps, and are limited in duration.

The following table shows the hedges outstanding at December 31, 2023: Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average Put Price Weighted Average Call Price (Bbls) (per Bbl) (per Bbl) 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 The following table shows the additional hedges entered into in 2024: Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average Put Price Weighted Average Call Price (Bbls) (per Bbl) (per Bbl) July 2024 - September 2024 Collars Dated Brent 80,000 $ 65.00 $ 92.00 The hedge counterparty will be obligated to make payments to us to the extent that the floating (market) price is below an agreed fixed (strike) price.

However, hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on our contract obligations. Disruptions in the market could also lead to sudden changes in the liquidity of the counterparties to our hedge transactions which in turn limit our ability to perform under their hedging contracts with us.

Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their non-performance, we could incur a significant loss.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when production is less than the volume covered by the derivative instruments or when there is an increase in the differential between the underlying price and actual prices received in the derivative instrument.

In addition, certain types of derivative arrangements may limit the benefit that we could receive from increases in the prices for crude oil. natural gas and NGLs, and may expose us to cash margin requirements. We are exposed to the credit risks of the third parties with whom we contract.

We may be exposed to third-party credit risk through our contractual arrangements with government entities party to our PSCs, our current or future joint venture owners, marketers of our petroleum and natural gas production, purchasers of our oil, natural gas and NGLs products and other parties.

In addition, we may be exposed to third-party credit risk from operators of properties in which we have a Working Interest or Royalty Interest. In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects.

In addition, poor credit conditions in the industry generally and among our joint venture owners may affect a joint venture owner’s willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until it finds a suitable alternative partner.

To the extent that any of such third parties go bankrupt, become insolvent, or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in our inability to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect our financial and operational results.

Our ability to collect payments from the sale of crude oil, natural gas and NGLs from our customers depends on the payment ability of our customer base, which may include a small number of significant customers. If our significant customers fail to pay for any reason, we could experience a material loss.

In addition, if our significant customers cease to purchase or reduce the volume they purchase of our crude oil, natural gas or NGLs, the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, our crude oil, natural gas and NGLs.