VAALCO Energy, Inc. Stock

Good day, and welcome to the VAALCO Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Landis Blackburn, Director of Investor Relations and FP&A. Please go ahead.

Thank you, operator. Welcome to VAALCO Energy's Second Quarter 2026 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the second quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before you take your questions. [Operator Instructions] We would like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparisons and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments.

During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and in the reports we file with the SEC, including our Form 10-K. Please note, this conference call is being recorded. Let me turn the call over to George.

Thank you, Landis. Good morning, everyone, and welcome to our second quarter 2026 earnings conference call. Over the past 2 years, we have streamlined and expanded our portfolio while delivering consistently solid operational results. In the first half of 2026, we have made material changes to our growing and diversified portfolio. We divested all of our Canadian assets while increasing our Cote d'Ivoire position. We were named operator with a 60% working interest in the Kossipo field on the CI40 block that had 2 discoveries drilled in the field and is located only 8 kilometers from Baobab.

We are actively evaluating and processing seismic with our partners in Niosi Marin and Guduma Marin blocks offshore Gabon and on our exploration block CI-705 in Cote d'Ivoire. The Baobab FPSO successfully completed its refurbishment and the field resumed production in June as planned. At Etame, we continue to execute on our drilling campaign. All of these events have led to improving financial results driven by increases in production and sales that we believe will continue into the second half of 2026. We delivered $42.4 million in net income and $54.8 million in adjusted EBITDAX in the second quarter.

We continue to deliver our increased sales and production targets, all while maintaining our capital expenditures in line with guidance. We are confident in our ability to continue and consistently execute and deliver value to our shareholders. I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire. We're excited to have production resume in Baobab in June 2026. As you know, in line with the project time line, the FPSO at Baobab ceased hydrocarbon operations in January 2025, spent a year being refurbished in Dubai and returned to Cote d'Ivoire in April 2026. We are very pleased how well the FPSO refurbishment went and that it was completed within the initial time line expected. All producing wells are online and production is slightly above our pre-start-up forecast with the first lifting expected later this month. The single Q3 lifting is expected to be about 950,000 gross barrels, but remember that we are a nonoperator with a 27.4% ownership.

The FPSO refurbishment was undertaken to extend the life of the vessel and to increase its capacity as we begin a significant development drilling program in Baobab in Q3. This program includes 4 producers, 2 or 3 injectors and 2 workovers, providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension to the license to 2038. The current drilling plan in Baobab is to begin drilling in the third quarter on a batch basis, the top hole sections of all wells first.

The completions will then commence, and we expect at least 1 well to be on production by year-end. With that said, production and sales uplift from the drilling program at Baobab will not make a significant impact until 2027. In February 2026, in accordance with the CI40 PSC, VAALCO and PetroCI elected to participate in the development of the Kossipo field. VAALCO was confirmed as operator with a 60% working interest in the Kossipo field on the CI40 block just 8 kilometers from the Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help derisk and enhance our evaluation and development plan.

Our current assessment has a field with an estimated gross 2C resources of approximately 102 million barrels of oil equivalent and 293 million barrels of oil equivalent in place. Also in Cote d'Ivoire, we continue to evaluate the subsurface potential of our new exploration block CI-705, which we operate with a 70% working interest. We continue to see encouraging prospectivity on the block in play types proven throughout the Ivorian Basin, including both structural and stratigraphic traps in the Upper Cretaceous and Albian sections. We have met all current work commitments on the block and have been granted a 6-month extension on the first exploration phase, which now extends this phase into Q4 2026.

Our subsurface work will continue to mature the encouraging prospectivity we see on block in preparation for a decision later this year to proceed to the second exploration phase, which carries a well commitment. I would like to remind you that we had no assets in Cote d'Ivoire prior to April 2024. So in less than 2 years, we have established a sizable position in Cote d'Ivoire, consisting of a producing asset with upside at Baobab, operatorship of a discovery at Kossipo with plans to develop and considerable upside potential on a prospective exploration block. We are excited about the prospects in Cote d'Ivoire and their ability to help us achieve our production growth target over the next several years.

Moving to Gabon. In the fourth quarter of 2025, we began our Phase 3 drilling program. I would like to note that working interest production in Gabon in Q4 2025 was 7,743 barrels of oil equivalent per day and declining. This program was designed to reverse decline and increase production by accessing potential attic locations and less swept fault blocks across the Etame field as well as access deeper potential in the Dentale and test an exploration prospect from the platform. The program began with the drilling of 2 pilot wells in the Etame field. One of these was sidetracked and completed as Etame 15-8 development well in the 1V fault block. This well came online in late February. So our Q1 production results had only 1 month of production from this well, which coupled with decline and some downtime resulted in Q1 working interest production of 7,516 barrels of oil equivalent per day.

The rig remained on the Etame platform to drill an exploration prospect in West Etame. While the well encountered 10 meters of high-quality Gamba sands, the target zone was water-bearing and not commercial. The lower portion of the well was plugged and abandoned, but the wellbore was utilized and sidetracked in the upper portion of the well to drill the ET-14H development well in the main fault block of Etame that was derisked from the results of the earlier pilot wells. In late April, the Etame 14H was brought online after encountering 325 meters of lateral net pay in high-quality Gamba sands in an attic position within the main fault block at Etame. Initial rates exceeded 4,800 gross barrels of oil per day and the well continues to produce about 3,000 gross barrels of oil per day. After completing our program at the Etame platform, we moved the rig to the Ebouri platform, where we drilled the Ebouri-5H development well.

This well had 300 meters of lateral net pay in Gamba sands at the crest of the structure and came online in late June with initial rates of about 8,000 gross barrels of oil per day with minimal water cut. While the total fluid rate has remained fairly consistent, the well has increased water production, approaching the field-wide average of about 75% to 80% water cut. While we expected the water cut to ultimately rise to the field average, the rate at which it has increased was faster than we initially expected, implying more reservoir connectivity than we had originally modeled. We are currently evaluating this well performance with a view to remodeling the Ebouri structure, which should provide better predictability on 5-8 performance. With that said, for Q2, we saw Gabon production increase to over 9,300 working interest barrels of oil equivalent per day with the additional well.

We moved the rig to the SEENT platform and drilled the ETBNM-3 well, a high GOR gas supply well that was completed a few days ago. Gas rates and volumes are in line with pre-drill estimates and will be used to improve field uptime, reduce costs associated with using higher-priced diesel and potentially add production uplift to existing wells. The rig has now skidded over to another slot on the SEENT platform and is drilling the ET-SEM3 pilot hole. Pilot is designed to aid in landing the lateral producer, test the original field oil water contact and also evaluate the potential of underlying Dentale formation. Once the pilot hole is completed, the horizontal development well is planned near the crest of the central fault block in Southeast Etame into Gamba sands.

Upon completion of this horizontal well, we are planning to release the rig and not perform any further drilling or workovers in Gabon in the near term. We have reduced the expected workover spend in the second half of 2026 from a range of up to $10 million to no spend due to excellent ESP life. This is because the wells in Ebouri continue to perform well with the chemical treatment, and we do not want to take these wells offline to perform maintenance workovers until it is necessary. Furthermore, when we do need to work over these wells, we can use our workover unit that we have in country to perform the workovers at an expected material cost savings compared to using the current drilling rig.

Regarding our exploration blocks in Gabon, the Niosi Marine and the Guduma Marine, we continue to work with our partners on plans for the 2 blocks moving forward. We commenced a 3D seismic survey in November of 2025, which was completed in the first quarter of 2026. The survey completed part of the exploration work program commitment for these blocks. Processing of the seismic data has begun with early products expected to arrive later this month. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks and we'll continue to mature prospectivity using the new seismic data. With the inclusion of the gas well providing fuel, we expect to see a marked reduction in operations costs.

In addition, we are reviewing the current operating model of the entire field to look for ways to structurally enhance our business to make the field more cost effective and efficient as we move forward. We expect this process will lead to a reduction in both CapEx and OpEx moving forward. Turning to Egypt. Over the past 2 years, we have drilled in excess of 20 wells across a drilling campaign that helped to increase production year-over-year in 2025 and 2026. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. Given these strong results, we resumed the drilling program in Egypt in May of this year. We are pleased with the overall production results, which is continuing to drive an increase in production rates into Q3. We are further expanding the scope of the Egyptian drilling program to include a total of 10 to 15 wells during the year.

The corresponding production uplift can be seen in our increased Egyptian guidance with no impact on our overall CapEx guidance for the year, which Ron will explain in more detail later in this call. We also plan to continue optimizations, workovers and recompletions in 2026 that are focused on production enhancement. Egypt production remains strong as we continue to invest to drill development wells and delineate opportunities in Ghazalat that could open additional prospects in the future. We will provide further details of the drilling results in our Q3 earnings call. Turning to Equatorial Guinea. In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. Last summer, we began a front-end engineering design or FEED study.

The initial FEED study is now complete and confirms the technical viability of our plan of development, but also highlights some of the risk and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which would also significantly simplify the drilling operations and well design, and this evaluation is currently underway. We are excited to proceed with our plans to develop, operate and begin producing from the discovery in Block P offshore. We are targeting Venus FID in Q4 2026. In closing, we have an outstanding diversified portfolio of both producing assets and assets with significant upside opportunities.

We are executing on our programs and the second half of 2026 should build on the positive second quarter results. We remain focused on growing production, reserves and value for our shareholders. I'd like to thank the hard-working team who continue to operate and execute our plans. Over the past several years, we have significantly diversified our portfolio, enhanced our capacity to generate operational cash flow while returning capital to shareholders and increasing our credit facility capacity. We are well positioned to execute the project and our enhanced portfolio and our proven track record of success these past few years instill confidence for the future. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George, and good morning, everyone. Following on from Q1 and as anticipated, we saw good growth both in revenue, profitability and operational cash flow. As George discussed, operationally, we were performing very well. And in the second quarter, we saw the impact being a material increase in our financial results. We had strong earnings in Q2 of $42.4 million or $0.39 per diluted share. We also generated $54.8 million in adjusted EBITDAX. I will highlight some of the factors that resulted in our improved Q2 financial results, including the timing and number of sales liftings, reduction in exploration expense and improvement in the unrealized derivative loss position for the year. A major factor impacting costs and indeed earnings in Q1 was exploration expense.

In the first quarter, we had cost of an exploration well at West Etame that was determined to be unsuccessful and additional seismic costs at the Niosi and Guduma blocks in Gabon. In the second quarter, we had virtually no exploration expense, a nearly $23 million difference. Net revenue more than doubled in the quarter. And in Q2, we had 2 partner liftings in Gabon for around 900,000 barrels gross each. While the production came back online in Cote d'Ivoire in June, no liftings occurred in Q2, but our entitlement inventory on the vessel grew with an anticipated lift now likely in August. Egyptian production and sales has been both strong and is rising due to a successful drilling campaign and sales volumes through the first half of the year were 7% higher than the same period in 2025.

Overall, production in Q2 was 16,688 NRI BOPD or 21,796 working interest BOPD, an increase of about 10% compared to Q1 2026. Sales of 17,812 NRI BOPD for Q2 were 47% higher than Q1 and above the midpoint of guidance. Revenue in Q2 was up $72.6 million compared to Q1, driven by higher realized pricing and the higher sales volume. Turning to costs. With a significant increase in sales, our production costs for Q2 on an absolute basis were higher than in Q1 and were slightly above the midpoint of guidance, driven by inflationary pressure on costs, primarily fuel driven by higher commodity pricing as well as freight costs impacting margin. Our focus remains on keeping our costs low to enable us to maximize margin and increase our cash flow. But with higher diesel and freight costs driven by the Iran conflict, we may see some expense increases in the near term.

Looking at G&A, our cash G&A totaled $9.6 million. The increase in general and administrative expenses was primarily a result of a $1.9 million of nonrecurring professional service and legal fees. Turning to hedging. As I have discussed in the past, our reserves-based lending facility requires us to have a more programmatic hedging program, which is more consistent over a rolling time horizon. Our strategy prioritized downside protection to safeguard cash flow to help fund capital commitments for the Cote d'Ivoire Baobab FPSO refurbishment, the Gabon Phase 3 drilling campaign, our debt servicing and the [indiscernible] dividend program. In March, oil prices spiked and we both realized and unrealized losses as we mark-to-market. This is reevaluated at the end of each quarter and the pricing at June 30 declined materially from March 31, resulting in an unrealized gain of about $40 million in the quarter.

Overall, we generally maintain between 30% to 40% of our production hedged at any period going out as far as 12 months. We have opportunistically entered into the market when we saw war premium spikes. You can see our overall hedge position with both the timing and the related Brent floor and collar strike for each period in our supplemental information deck. Moving to taxes. In the second quarter, we reported an income tax expense of $16.8 million, which was comprised of a $15.8 million current tax expense and a deferred tax expense of $1 million. Income tax expense included a $1 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of profit oil between the time it was produced and its present mark-to-market liability.

In Q1, we had a state listing in Gabon, which settled our tax position. And we do not see another state listing in 2026 with our cost pool maximized with the spend under the drilling program, which is first to be recovered. Similarly, we do not see a state listing in Cote d'Ivoire in 2026. And in Egypt, the tax barrels are settled monthly from the government's take. Turning now to the balance sheet and cash flow statement. In Q2, we invested $103.6 million on a cash basis and $98.9 million on an accrual basis and net capital expenditures. This was well below the low end of our guidance range. This is primarily related to new wells drilled as part of the drilling campaign in offshore Gabon as well as expenditures associated with the refurbishment and reconnection activities of the FPSO in Cote d'Ivoire.

Thus far in 2026, Cote d'Ivoire has seen some additional capital costs over what the operator originally guided to, but this has been offset primarily by our own drilling performance in Gabon as well as deferring some nonessential CapEx. We have seen excellent performance from our drilling team in Gabon, and we've seen each well to date come in below its predrill budgeted approval for expenditure. This, together with some Etame engineering projects moving into 2027 and continued good collections in our Egyptian business has allowed us to expand our capital budget in Egypt to allow us to drill more wells in 2026 at no overall increase in projected capital spend for the year and no overall impact to 2026 free cash flow.

This will allow Egypt to exit the year at far higher production rates than we originally envisaged back in our guidance call in March. Unrestricted cash at the end of the second quarter was $30.4 million. In the second quarter, to help fund our capital programs, we did draw $25 million against the company's RBL. In April, the aggregate borrowing base under the 2025 RBL facility increased to $300 million. We now have $177 million drawn on the credit facility with net debt of $147 million. Last call, I discussed how pleased we were in 2025 and Q1 2026 with the progress made with our Egyptian receivables. We continued in the second quarter as we saw an additional reduction to our trade receivables of about $11.5 million with our trade receivables falling from just over $24 million at Q1 to just under $30 million at the end of Q2.

We continue to work with the Egyptian General Petroleum Corporation to maintain this strong relationship and keep our receivables current. I'd like to call out specifically our leadership team in Cairo who continue to do great work in this area. In Q2 2026, VAALCO paid another quarterly cash dividend of $0.25 per common share or $6.7 million. We also announced the third quarter dividend payment, which will be paid in September. Let me now turn to guidance, where I'll give you some key highlights and updates. As discussed in the past, guidance for the remainder of 2026 has no contribution from the Canadian assets that were sold in February. With the strong performance of our drilling campaign, coupled with the restart of production at Baobab and some additional drilling in Egypt, we expect to see strong increases in production and sales continue into the second half of 2026.

For Q3 sales, we are expecting the midpoint of guidance to be only slightly higher than the Q2 actuals. This is driven by cargo sizes and mix across our assets. In Q3, we will have our first lifting in 2026 at Cote d'Ivoire with the Baobab field resuming production in June. This lifting is expected to be around 950,000 barrels gross. We have a 27.4% working interest ownership. Additionally, we will have 2 partner liftings in Gabon as we did in Q2, but these liftings are expected to be smaller in size than the Q1 liftings. With the continued uncertainty around war premium pricing and physical needs due to the conflict, buyers and traders on the spot market are looking for smaller cargoes and deferring entering into agreements more than a few days out from the liftings.

We expect the third quarter 2026 net revenue interest sales volumes to range between 17,200 and 18,900 barrels of oil per day. For Q3, we're also projecting total production to be higher by about 23% compared to Q2 as we see additional wells brought online and production in Gabon in Egypt and the full quarter's production in Cote d'Ivoire. For the total company, we are forecasting Q3 2026 production to be between 24,400 and 26,900 working interest barrels of oil per day and between 19,600 and 21,600 net revenue interest barrels of oil per day. For the full year production guidance, as George mentioned, we see some production increases in Egypt and Cote d'Ivoire that are offset by some slight decreases in Gabon. But overall, we are confident in the performance of our diversified assets, and we are reaffirming the sales and production increase we conveyed last quarter.

Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with production breakout of both working interest and net revenue interest by asset area. We expect our absolute production cost for Q3 to be in the range of $25 to $29 per NRI barrel of oil. This is slightly lower than Q2 as we're expecting some sales increase with costs remaining flat or decreasing slightly on an absolute basis. For our exploration expense, we are forecasting a range between $3 million and $4 million for Q3. This is primarily seismic processing work in both CI-705 as well as similar processing work by our partner in Niosi and Guduma blocks. As George discussed, we are dropping the offshore workover guidance to 0 for Q3 and for the full year. We expect cash G&A to be in the range of $7 million to $9 million.

Finally, looking at CapEx, our Q1 and Q2 spend has been below the guidance range, some of which is timing, some of savings. As George mentioned, we are adding wells to our Egyptian program, but maintaining our full year capital expenditure midpoint. For Q3 2026, our capital spend is projected to be between $75 million and $115 million as we continue the drilling campaign in Gabon, prepare for the drilling campaign at Baobab and drill additional wells in Egypt. George outlined the multiple programs across our assets, and we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future.

In closing, we saw material improvements in our Q2 financial results that we guided to in May and expect the second half of 2026 will continue to see increasing production, sales volumes and margins depending on the stability of current Brent pricing, which should produce favorable financial results as we upscale our netbacks from the greater West African mix of barrels in the second half of the year as well as a switch from expensive bunker diesel running costs in the Teli in Gabon to field gas. We believe we will remain well positioned to continue executing our strategy of growing production and reserves while adding meaningful value. Early 2027, we'll continue to see growth in our production, sales and margins as our Cote d'Ivoire Phase 5 drilling comes online. With that, I'll now turn the call back over to George.

Thanks, Ron. We have started 2026 with some very positive results across our programs in Cote d'Ivoire, Gabon and Egypt. The restarting of the Baobab field in Cote d'Ivoire in June, the wells in our Gabon program and the ongoing drilling in Egypt are driving these increases. As we look at the second half of 2026, we are projecting significant increases in production and sales, which coupled with continued attractive pricing should generate solid operational cash flow and adjusted EBITDAX generation. As Ron outlined, our production and sales guidance is up about 10% compared to our original estimates and our CapEx has not changed. We have successfully delivered strong operational and financial results for the past several years where we have met or exceeded guidance on a quarterly basis, and we believe that we can continue to meet or exceed our guidance numbers in Q3 and beyond.

Our ability to remain focused on successfully executing our strategy is key to growing the company profitably over the remainder of the decade. There are numerous macro events that we cannot control, but the things that we can control by operating efficiently, investing prudently and maximizing our production will help us to deliver the forecasted growth and profitability for our shareholders and partners. We are actively working to continue to deliver strong results that will fund our successful capital programs and drive growth, all while returning value to our shareholders through a top quartile dividend. We have maintained credibility over the past several years, having delivered on our commitments to the market and to our shareholders, and we'll continue to deliver with the exciting slate of projects that we have over the next few years. We are in an enviable position with a much stronger and diverse portfolio of producing assets with expected significant future upside potential. Thank you. And with that, operator, we're ready to take questions.

[Operator Instructions] The first question today comes from David Round with Stifel.

First one, just on the recent gas well, I mean, it looks like a good result in its own right. But could you just expand on what you saw in the shallower intervals and whether there are any potential implications from those, please?

Thanks, David. Well, in the shallower intervals, we did see some shows on hydrocarbons. We did expect that. But unfortunately, we can't, at the moment, produce that because of the well design. The well design was purely designed to go down to that specific zone for the gas development. But it has been tagged and sometime in the future, that could be recompleted as a producer.

Yes. Just to add to that, I mean, we logged obviously on the way down and our subsurface people are looking at that. But yes, as George mentioned, it's not completed with the ability to produce in those zones.

Okay. Great. And a follow-on, I guess, on a similar topic, in terms of the gas you have encountered, I'm interested how quickly we could see that feed through to OpEx. George, from what you were saying earlier, it sounds like there's some easy wins and then maybe a bigger piece of work going on here now. I don't know if that is as a result of encountering better pay than you expected or whether that maybe was always the case. But I suppose I'm just wondering if that bigger piece of work could result in even higher savings than maybe you've talked about before.

I'll let Ron talk about the savings, and then I'll jump in after that.

David, if you look at the first half of the year, I mean, this gas well was brought online at the very end of July. So it's effectively 7 months. The key one here is the tell, which is the FSO it's operating in Gabon. Over that time period, indeed at the end of 2025, we were running that fully on diesel. We've now managed to switch that back fully on to gas. Now there are some elements of it on the platforms themselves, but the big one really is the Teli. And that's roughly about 300 to 350 cubes per month in volume.

So that's really the guidance, I would say, from August through to December, you'll see that reduction in volume in diesel usage. Of course, that's a gross number. We were 58% of that. We have seen increasing pricing on that cube for diesel fuel through the first 6 or 7 months. I would use probably an average of between $1,500 and $1,600 per cube, but we definitely saw a 25% increase come in just in July. So it's opportune that we've got the switch to gas at this point in time.

The other thing to add there is, obviously, the gas is not just there for fuel. It's also there for gas lift and it's there to improve the performance of the compressors. And with that, we're going to see enhanced production.

Reliability.

Reliability and production. I mean our subsea wells have been performing poorly because of lack of gas lift.

Yes. I mean so some of our wells are on gas lift with the compressor. And under diesel, we just couldn't operate at the high enough RPMs to maximize or optimize the gas lift. With gas, we can do that, and we're already seeing that. In addition to that, gas is a lot more stable of a fuel for our turbines, which increases reliability. So it pushes our entire operation, I guess, to a far higher reliability factor than we are now.

So we haven't quantified yet, but we will see -- we will see enhanced oil recovery numbers coming from these wells.

The next question comes from Stephane Foucaud with Actus Advisors.

So I'd like to come back to production. So I think you covered very well that the increased number in Egypt was based on increased activity. I think that on Gabon CI, from my understanding, that might be around the fact that the early production since you restarted has been better than expected. Could you perhaps come back on why then Gabon is at the lower end of expectation, whether it's timing of activity given the change of the work program, whether it's well, whether it's this issue that you described around the lower production efficiency. I think we have 93%. What's happening? That would be my first question.

Okay. Well, the main issue there comes down to the 5H well that I mentioned earlier on the call today. The level of decline in that well was far higher than we anticipated and modeled. So we started off at a very high production rate of over 8,000 barrels of oil per day, but the water cut raised far quicker than we anticipated, far quicker than we had modeled, as I mentioned in the call. And we're going to have to go back and look at that to increase our ability to accurately predict the 5H performance. So it's just -- we've predicted that 5H performance now as a plateau from where we are today as opposed to at this point in the original decline curve, we had a much higher production rates. And that's the main reason for the decline.

Okay. That's great. And the second one is on Kossipo. I think you have previously said you were looking to submit the FDP, I think, later in '26. I think now we are talking about H1 '27. So this is indeed a change of timing. What is behind that? What are the key steps that we need to watch for that FDP to be submitted?

Okay. So when we talked about the FDP in the previous call and as I mentioned in the Q1 call, we were still in discussions with the DGH at that time. We were committing to the DGH that we can pull out all the stocks possible to try and meet the original deadline that the original operator had committed to when we got the license extension. At the same time, with our partner, PetroCI, we were lobbying the DGH to say, look, in order to get this as accurate and as good as possible, we really look for a 6-month extension to the submission deadline, which we agreed to. And that's why that's the main change is we've been given that extension by the DGH and we're going to take that time to prepare both the teams and the higher quality FDP document for submission.

The next question comes from Jeff Robertson with Water Tower Research.

George or Ron, can you talk a little bit about the cost structure in -- at Baobab and how with production rising into 2027, that might impact VAALCO's overall cost structure?

Yes. That's a good question, Jeff. Obviously, we came back up a little bit earlier in CDI than we originally had looked at together with the operator. We came back up and running in June. So that's good news. Obviously, as the wells come back online and then we proceed to Phase 5 drilling, again, the scale will help on the overall per barrel costs. Directionally, this year, we've probably got a couple of things in there that is causing the variable cost to be a little bit higher than what we anticipated when we went into the budget year. There's 2 things. The operator is changing out the O&M, but it's been taking a little bit longer for them to do that than they first anticipated.

So we should see a saving as we go through 2027 as that rolls out. The second thing, and you'll see it in Q4, where our production cost comes up a little bit, they're taking the opportunity and the advantage with the vessels in that area to do some ROV inspection work. So again, Q4, I think, spikes up a little bit versus Q2 and Q3 in CDI. But overall, directionally, this is by far the lowest lifting costs that we have in our portfolio. And as we go through 2027, that's only good news for the overall cost structure of VAALCO.

Ron, as you move more barrels through that facility in 2027, would just the fixed cost over more barrels result in a lower unit lifting cost?

That's exactly it, Jeff. I think what you'll see is 2 things. I think the run rate, which is really only just half a year for 2026. I think if you take that run rate, you'll see it come down in '27 on an absolute basis, and then you'll see the volumes go up. So I think what you'll see is a double advantage there on a per unit basis.

One last one on that. Ron, can you talk a little bit about what you expect for pricing relative to Brent for CI barrels?

It's a little bit too early, Jeff. What I would say is we're seeing a very volatile market, as you're well aware. Depending on the news from Washington or Tehran, it's moving quite a bit. So what we've seen is that the refineries are basically delaying until they need to cargoes. So that's why if you look at our Q3 cargoes that we've got in Gabon, they're going to be probably 600,000 gross cargoes rather than the 900,000 that we had in Q2. And that's specifically people are waiting to the last minute because they're always thinking it Brent is going to fall in relation to any good news coming out from Washington or Tehran. So very difficult to say, but over the piece, that crude's a good assay, and it should at least trade at Brent.

The next question comes from Bill Dezellem with Tieton Capital.

Ron, would you please circle back to the cost savings from shifting to natural gas from diesel. I apologize here on the fly, I don't have a conversion for cubes to gallons. And ultimately, I recognize that prices are higher today than maybe they will be on a normalized basis going forward. So could you tell us kind of the annual savings that you would expect based off of what historically have been normalized diesel prices and just maybe bring it right down to how many million.

Yes, no problem, Bill, we can do that. So effectively, what you're looking at is a -- basically a cubic liter is 1,000 liters of diesel. That's been priced, I would say, in the first half of the year, our average is probably about $1,500 to $1,550 per cube. What you will see is from a gross basis, that's a reduction per month of about $500,000 to $600,000 per month. And of course, we are about 58% of that. So I would work that in from August onwards.

Okay. $5,000 to $6,000 a month...

No $500,000 to $600,000 per month gross, and we're roughly 60% of that.

Great. Thank you for that clarification, and apologies for missing that. And then second, what do you anticipate to be the quarter where you have your peak level of debt given the current drilling program, assuming no future acquisitions, but just the CapEx from the drilling and then the offsetting benefit from production.

Yes. I think I would point you back to our investment deck that we went out on our non-deal roadshow over the last 2 months, and we put some forecast in there that are still pretty good in relation to where we saw that debt going this year. At this point in time, my modeling is actually showing peak debt in Q1 2027 because we got Phase 5 drilling going through and into completions in 2027. So I see that kind of peaking out in Q1 2027, but it all depends on the $64,000 question, Bill, as to what Brent pricing does over that time period.

Absolutely. And then I'm going to squeeze in one more, if I may. The H2S problem that you've been working on in Gabon, is that now totally solved or partially solved? And if it's partially solved, how much future production could you get if you are able to fully solve it?

The H2S in the existing wells that we have is being controlled with downhole injection and topside injection. And we seem to be able to handle all the H2S that we're seeing coming out of those wells. So there's no problem with dealing with the H2S with the injection program we have now. Until we actually understand, I guess, the sort of ramifications of 5H, it's going to be hard for us to point to additional volumes there.

Yes. I mean I think I mentioned, Bill, in the call earlier, we're going to have to -- because 5H decline was accelerated beyond our modeling position, we're going to have to rework the geo model. So probably over the next 4 or 5 months, we'll have a much better predictability. But the performance of the downhole injection, surface injection scavenger has been extremely good. And the breakthrough of what the scavenger is dealing with on H2S for PPM continues to be lower than our predicted models.

Great. And then I'm actually going to break the rules and ask one more, if I may. The Cote d'Ivoire production, what is the production rate coming as you've done the start-up versus when you took the field down? Is there an initial pressure benefit that you're experiencing?

Yes, there is flush production coming through, and we expect that to continue. We're probably running around 16,400 to 16,500 barrels a day gross production, which is about -- I'm going to say about 2,000 a day more than the original number that we were using or we had prior to shut down. The wells themselves came on extremely well and smoothly. There's obviously a concern after a well has been down for that length of time to bring it back on again, but we had absolutely no issues there.

The operator did a great job in bringing them on. We're seeing no sand come through. We're seeing everything stable. And there is still a bit of upside on the wells. We're just very cautious or the operator is very cautious about opening those wells completely up. So yes, it's good news.

We now have a follow-up from Stephane Foucaud with Actus Advisors.

Yes. I was wondering about the exploration program in Gabon and the seismic and whether on data review, you will be providing some sense of the size of the price on those exploration licenses? And if yes, when would that be?

Yes. We're still receiving some of the data sets. So it's probably on the size of the price around Niosi and Guduma and that's really going to be into mid-'27 before we can really target that with our partner, BW Energy and Panoro. We're probably going to be earlier than that when we look at CI-705 because obviously, we've got a decision we make this year, and we'll probably come out in Q4 with some bigger indications of what we see as targets for the Cote d'Ivoire exploration assets that we operate. But when I say Guduma, it's likely to be well into '27.

Okay. And secondly, for Ron. I was looking at the -- so the expected working interest of the sales in Q3 versus production because as you mentioned, the sales will be a bit lower than production for the reason you explained. Now does that suggest you would expect in Q4 a reversal of that? So should we expect a big Q4 looking at liftings?

Can you repeat that question a little bit there?

So I was looking at -- so in Q3, working -- production is higher than sales for the reason, I think, of the lifting that you have described. But on a full year basis, it's quite similar. So does that suggest that you might have a very strong quarter in terms of sales, in terms of listings in Q4, offsetting Q3?

Yes, yes. I mean if you look at Q4 at the moment, the way we planned, we're seeing 3 listings in Gabon and a couple of listings in Baobab. So yes, Q4 will be stronger than Q3.

Yeah. Would be strong.

The next question comes from Jamie Wilen with Wilen Management.

Wonderful results. But a question on taxes moving forward. Can you tell me what the cost oil is in Gabon as well as Cote d'Ivoire? And how much of the next generation -- generated pretax profits are going to run for VAALCO?

Jamie, it's Ron. I'll do my best to answer that question in relation to, obviously, the taxes in U.S. GAAP. First and foremost, in relation to the cost pools, we are -- we've got a maximum cost pool in both Gabon and in CDI due to the spend on the drilling programs as well as obviously the monthly OpEx. So -- and I think we've communicated this in relation to the non-deal road shows. That Gabon cost pool should see us through. Again, the big question here always is going to be where Brent lies. Now if Brent is $100 per barrel, then it accelerates the recovery of that quicker. But if we look at long-term price maybe in the 70s, we see that Gabon cost pool being pretty robust right through 2027.

So again, minimal state liftings, you would think in 2027 at those prices. CDI, we probably got multiple years' worth of shield in relation to the cost oil. So you're probably looking at about 3 years before the profit really creeps up in CDI. Obviously, when you look at U.S. GAAP purposes from a P&L point of view, you've got the picture of the cost pools themselves providing a deferred benefit. And obviously, the part of U.S. GAAP there is to smooth out these peaks and troughs. So your P&L and your actual cash cost on tax are completely 2 different things. What I would say to you is '26 and '27 will be our lowest, I would say, entitlement barrels to the state during those time periods in Gabon. And indeed in CDI, we see that benefit probably going out 2 or 3 years from now.

At this time, there are no more questions. I would like to turn the conference back over to George Maxwell, CEO, for any closing remarks.

Thank you, operator. Well, once again, I think we've delivered a very strong quarter. We've indicated a stronger performance and guidance for 2026. Ron and I just completed an undue roadshow, which I would direct investors towards, it's on our website that shows the level of activity that the company have in our current portfolio going through to 2030.

And you can see the growth opportunities that exist in the development of our assets that will take the company to a working interest position somewhere north of 60,000 barrels per day, which is quite meaningful from where we are today. But we have -- we should celebrate a great set of results for Q2, great operational performance by our drilling team here in -- the drilling team in Gabon coming under budget with the activity and allowing us to increase activity in Egypt without increasing our CapEx guidance, which is a significant result, resulting in the higher guidance on production that Ron announced today. So with that, I congratulate everyone in the company that's helped contribute towards these performances, and I look forward to talking to you in the Q3 earnings call. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Good day, and welcome to VAALCO Energy's First Quarter of 2026 Earnings Conference Call. [Operator Instructions] Also, please be aware that today's call is being recorded. I would now like to turn the call over to Investor Relations Coordinator, Chris Delange. Please go ahead.

Thank you, operator. Welcome to VAALCO Energy's First Quarter 2026 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the first quarter. Ron Bain, our CFO, will then provide a more in-depth financial review.

George will then return for some closing comments before we take your questions. [Operator Instructions] I would like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparisons and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments.

During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and thus actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and in the reports we file with the SEC, including our Form 10-K. Please note that this conference call is being recorded. Let me turn the call over to George.

Thank you, Chris. Good morning, everyone, and welcome to our first quarter 2026 earnings conference call. Over the past 2 years, we have streamlined and expanded our portfolio while delivering consistently solid operational results. In February 2026, we divested all of our Canadian assets and simultaneously added to our Cote d'Ivoire position by being named operator with a 60% working interest in the Kossipo field on CI-40 block. We are actively evaluating and processing seismic with our partners in Niosi Marin and Guduma Marin blocks offshore Gabon and on our exploration block CI-705 in Cote d'Ivoire. At Etame, we have had several successful wells drilled and the rig has now moved to Ebouri to drill the next well in our drilling campaign.

The Baobab FPSO has successfully completed its refurbishment and is now moved back into position with wells being reconnected and production expected to resume in early June. As we discussed our operational and financial results today, it is important to remember that 2025 was a transitional year for VAALCO as production came offline in Q1 at Cote d'Ivoire due to the FPSO project, and we did not start the drilling campaign in Gabon until late Q4.

First quarter 2026 was a pivotal quarter operationally, and we are beginning to see the significant production uplift we are projecting from these major projects in Q2 2026 and expect it to continue into 2027. We are confident in our ability to execute and have increased our full year 2026 production sales guidance and added to our work program without increasing our capital expenditure guidance. I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire.

I would like to remind you that we had no assets in Cote d'Ivoire prior to April 2024. Since that time, we have developed a significant production and prospective portfolio. In line with the project timeline, the FPSO at Baobab ceased hydrocarbon operations in January 2025. Following a year of refurbishment in Dubai, the FPSO returned to Cote d'Ivoire in April and is now moved into position, and we have 4 out of the 7 risers and umbilicals connected.

We expect the field to restart production in June with sales commencing from the FPSO in Q3. We are very pleased how well the FPSO refurbishment went and that it was completed within the initial time line expected. The refurbishment was undertaken to extend the life of the vessel and to increase its capacity as we begin a significant development program at Baobab later this year.

The program includes 4 producers, 2 or 3 water injectors and 2 workovers, providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension of the license to 2038. The current drilling plan on Baobab is to begin drilling on a batch basis, the top-hole sections of all wells. These completions will then be commenced, and we expect at least 1 well to be on full production by year-end.

In February 2026, in accordance with the CI-40 PSC, VAALCO and PetroCI elected to participate in the development of the Kossipo field. VAALCO was confirmed as operator with a 60% working interest in the Kossipo field on the CI-40 block just 8 kilometers from the Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help derisk and enhance our evaluation and development plan.

The Kossipo field was discovered in 2002 with the Kossipo-1X well and later appraised in 2019 with the Kossipo-2A well, which tested at over 7,000 barrels of oil per day. Our current assessment has the field with an estimated gross 2C resources of approximately 102 million barrels of oil equivalent and 293 million barrels of oil equivalent in place.

Also in Cote d'Ivoire, we continue to evaluate the subsurface potential of our new exploration block, CI-705, which we operate with a 70% working interest. We continue to see encouraging prospectivity on the block in proven play types through the Ivorian Basin, including both structural and stratigraphic traps in the Upper Cretaceous and Albian sections. We have met all current work commitments on the block and have been granted a 6-month extension to the first exploration phase, which now extends this phase into Q4 2026.

Our subsurface work will continue to mature the encouraging prospectivity we see on the block in preparation for a decision later this year to proceed to the second exploration phase, which carries a well commitment. So in less than 2 years, we have established a sizable position in Cote d'Ivoire with considerable upside potential.

We are generally excited about the prospectivity in Cote d'Ivoire and their ability to help us achieve our production growth targets.

Moving to Gabon. In the fourth quarter of 2025, we began our Phase 3 drilling program with the drilling of 2 pilot wells in the Etame field. Based on the pilot well results, we proceeded with the drilling of Etame 15H development well on the 1V block of Etame in December 2025. This well came online in late February at about 2,000 gross barrels of oil per day, so our Q1 production results only had 1 month of production from this well.

The rig remained on the Etame platform to drill an exploration prospect in West Etame. While this well encountered 10 meters of high-quality Gamba sands, the target zone was water-bearing and not commercial. The lower portion of the well was plugged and abandoned, but the wellbore was utilized and sidetracked in the upper portion of the well to drill the Etame 14H development well in the Main Fault Block of Etame that was derisked from the results of the earlier pilot wells.

In late April, the Etame 14H was brought online with an impressive initial rate of around 4,850 gross barrels of oil per day. This well encountered 325 meters of lateral net pay in high-quality Gamba sands in an attic position within the main fault block at Etame. Our second quarter production at Gabon should be enhanced by 2 months of production from this very successful well.

After completing a program at the Etame platform, we moved the rig to the Ebouri platform, where we are drilling a development well and a workover well to enhance production, lower costs and potentially add reserves. We also plan another 2 wells at SEENT platform following the completion of the program at Ebouri. We expect that development well at Ebouri to be completed later this quarter, and we plan to announce the results to the market when that happens.

Regarding our exploration blocks in Gabon, the Niosi Marin and Guduma Marin, we are working with our partners on plans for the 2 blocks moving forward. We commenced a seismic survey in November of 2025, which was completed in the first quarter of 2026. This survey completed part of the exploration work program commitment for these blocks. Processing of the seismic data has begun with early products expected to begin arriving later this year.

Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks.

Turning to Egypt. For the past year, we have contracted a rig and drilled about 20 wells across a drilling campaign that helped to increase production year-over-year in 2025. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. In conjunction with our drilling program, we also continue to perform production optimizations, workovers and recompletions that have significantly improved our production performance.

While we wrapped up the drilling program in the fourth quarter of 2025, given the strong results, we have added a 6-well drilling program in Egypt that is commencing in Q2 and which should help increase production in Q3. We have not increased our CapEx guidance for 2026 for the cost of these wells as the range we provided in March can comfortably include these new wells.

We also plan to optimizations, workovers and recompletions in 2026 that are focused on production enhancement. Egypt production remains strong, and we continue to invest to drill development wells and continue to delineate opportunities in Ghazalat that could open additional prospects in the future.

Turning to Equatorial Guinea. In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. Last summer, we began our Front-End Engineering Design or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risks and challenges from the shelf location.

We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which could also significantly simplify the drilling operations and well design and this evaluation is currently underway. We are expecting to proceed with our plans to develop, operate and begin producing from the discovery in Block P offshore. We are targeting Venus FID in 2026.

In closing, we have an outstanding diversified portfolio of assets that we believe have significant upside opportunities. We remain focused on growing production, reserves and value for our shareholders. I'd like to thank our hard-working team who continue to operate and execute our plans. Over the past several years, we have significantly diversified our portfolio, enhanced our capacity to generate operational cash flow while returning capital to shareholders and increasing our credit facility capacity.

We are well positioned to execute the projects in our enhanced portfolio and our proven track record of success these past few years should instill confidence for our future. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George, and good morning, everyone. I will provide some insight into the drivers for our financial results with a focus on the key points and give additional insight into our 2026 guidance. As George discussed, operationally, we are performing very well, but the first quarter was an inflection point for us financially.

I want to begin by highlighting the multiple factors that impacted our Q1 financial results, including the timing and number of liftings in Gabon, exploration expense and both realized and unrealized derivative losses. I want to point out that in the previous conference call and in our Q1 guidance, we discussed the reduced sales volumes expected in Gabon due to the sole lift being a government lift.

As I previously stated, in Gabon, Egypt and Cote d'Ivoire, our foreign income taxes are settled by the government through oil liftings in Gabon and Cote d'Ivoire and the government taking their share in Egypt. We also sold the Canadian assets in February, and as a result, only had a portion of production and sales from those assets in Q1.

Additionally, as George discussed, Cote d'Ivoire remained off-line for the FPSO refurbishment and production should resume by the end of the second quarter. Despite all these factors, our Q1 sales and production were both slightly above the midpoint of our guidance. We forecasted that Q1 sales would be quite a bit below production, but the midpoint of the full year production and sales guidance are much more in line, which means sales will likely exceed production in future quarters.

This can be seen in our Q2 guidance. While Q1 sales had no partner listings in Gabon, we expect 2 partner listings in Q2, which is expected to significantly increase our sales, revenue and ultimately, our adjusted EBITDAX. Another major factor impacting earnings and the expenses in the first quarter was the $22.4 million in exploration expense. This was driven by the cost of an exploration well at West Etame offshore Gabon that was determined to be unsuccessful and additional seismic costs at the Niosi and Guduma blocks in Gabon.

In the previous call, we also discussed the forecasted exploration expense and Q1 actually came in below the guidance range of $27 million to $32 million. Nearly all of our expected annual exploration expense came in, in Q1.

Turning to hedging. In the first quarter of 2025, we entered into a new reserve-based lending facility to help provide VAALCO with the short-term funding to supplement our internal cash flow generation as we have multiple large capital projects underway across our portfolio. Over the past year, we've been talking about a more programmatic hedging program that will be more consistent over a rolling time horizon.

We are looking to mitigate risk and protect the cash flow needed for our capital investments and shareholder distributions through the ongoing hedging program. Prior to the Iran conflict, the hedging program consisting primarily of collars allowed us to protect our downside risk and lock in a range of prices that allowed us to generate strong cash flow.

As you know, the market has been very volatile since March, and our hedges had about $15 million in realized losses in the first quarter, with an additional $56 million in unrealized derivative losses as we mark-to-market the positions. We had 56% of our guided Q1 barrels hedged with costless collars, the unhedged positions being largely represented by the Egyptian sales where the PSC terms provide the state with 85% of the pricing upside over cost of oil and the contractor 15%. We are continuing to monitor the situation and hedge on any geopolitical shock or spike where we can.

With Cote d'Ivoire coming back online, we will have more oil barrel sales unhedged in Q3 and beyond. Our full quarterly hedge positions are disclosed in the earnings release.

Turning now to the first quarter results. We reported a net loss of $93.7 million in Q1 2026, which was driven by $71 million in derivative losses, of which $56 million represents unrealized book losses and a $22.4 million exploration expense.

While most of our expected exploration expense for 2026 occurred in Q1, with the uncertainty in macro events and oil pricing, our realized and unrealized derivative losses could continue to impact earnings in the coming quarters.

We also generated adjusted EBITDAX of $11.6 million, which included no partner liftings in Gabon and no sales in Cote d'Ivoire. Q2 2026 is expected to be materially improved due to the 2 planned partner liftings in Gabon and a Q3 2026 sales is expected to include Cote d'Ivoire. With the FPSO expected to be fully operational in June, we are forecasting some production in Cote d'Ivoire in Q2, but there won't be any liftings until Q3.

Production in Q1 was 15,110 NRI barrels of oil equivalent per day or 19,884 working interest BOEPD, both above the midpoint of VAALCO's guidance. As I discussed earlier, sales of 12,157 NRI BOEPD for Q1 were slightly above the midpoint of guidance, but quite a bit lower than production.

Turning to costs. With no partner liftings in Gabon, our production costs for Q1 on an absolute basis were quite a bit lower than in Q4 2025 and were well below the midpoint of guidance, both on an absolute basis and on a per barrel basis. Our focus remains on keeping our costs low to enable us to maximize margins and increase cash flow.

But with higher fuel and service costs driven by the Iran conflict, we may see some expenses increase in the near term. Looking at G&A, our cash G&A totaled $6.9 million, which was below the low end of guidance.

Moving to taxes. In the first quarter, we reported an income tax expense of $4.3 million, which was comprised of a $14.9 million current tax expense, offset by deferred tax benefit of $10.6 million. Income tax expense included a $2.9 million unfavorable oil price adjustment as a result of the change in value of the government's allocation of profit oil between the time it was produced and its present mark-to-market liability.

Turning now to the balance sheet and cash flow statement. In Q1, we invested $78.1 million on a cash basis and $73.3 million on an accrual basis and net capital expenditures. This was primarily related to new wells drilled as part of the drilling campaign in offshore Gabon as well as expenditures associated with the refurbishment and reconnection activities of the FPSO in Cote d'Ivoire.

Keep in mind, we wrote off the cost of the unsuccessful West Etame well, so that cost is not in CapEx. Unrestricted cash at the end of the first quarter was $48 million. In the first quarter, to help fund our capital programs, we did draw $92 million against the company's reserve-based lending facility.

In April, the aggregate borrowing base under the 2025 RBL facility increased to $300 million. We now have $152 million drawn on the credit facility and net debt of $104 million. We anticipate a substantial part of the interest we incur this year from the facility borrowings will be capitalized and is in our capital guidance.

Last call, I discussed how pleased we were in 2025 with the progress made with our Egyptian receivables. And I said that we expected to see collections to exceed revenue in Q1 2026. For the first quarter, we saw an additional reduction to our trade receivables of about $7.4 million with our trade receivables falling from just under $32 million at year-end 2025 to just over $24 million at the end of the first quarter 2026.

We will continue to work with the Egyptian General Petroleum Corporation to maintain this strong relationship and keep our receivables current. In Q1 2026, VAALCO paid another quarterly cash dividend of $0.0625 per common share or $6.7 million. We also announced the second quarter dividend payment, which will be paid in June.

Let me now turn to guidance, where I'll give you some key highlights and updates. As I mentioned earlier, guidance for the remainder of 2026 has no contribution from the Canadian assets that were sold in February, and we are forecasting the Baobab field in Cote d'Ivoire coming back online in June with sales resuming in Q3.

With the strong performance of our drilling campaign, coupled with the restart of production at Baobab and some additional drilling in Egypt, we expect to see strong increases in production from Q1 levels moving forward. Additionally, with 2 partner listings in Gabon expected in Q2, our sales guidance is 44% higher in Q2 at the midpoint compared to Q1 sales.

We are confident in our operational abilities and are increasing our full year 2026 production and sales NRI volumes by 8% and 12%, respectively. Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with production breakout of both working interest and net revenue interest by asset area.

For the total company, we are forecasting Q2 2026 production to be between 21,600 and 23,800 working interest BOE per day and between 16,800 and 18,700 NRI BOE per day. This is a significant increase over Q1 production. We expect our second quarter 2026 NRI sales volumes to range between 16,800 and 18,300 BOE.

We expect our absolute production cost to be higher in the second quarter, in line with the additional sales volume and on a per BOE expense to be in the range of $26 to $31 per NRI BOE. This is slightly higher than Q1 as we are expecting some cost increases primarily related to fuel costs and reflects a higher mix of West African barrels versus North African barrels that dominated the mix in Q1.

For our exploration expense, we are forecasting a range of between $2 million and $3 million for Q2, a 90% reduction compared to the first quarter. We expect cash G&A to be in the range of $7 million to $9 million, and our annual G&A guidance remains the same.

Finally, looking at CapEx, our Q1 spend was below the guidance range, but we believe this is primarily due to the timing. Our Q2 2026 capital spend is projected to be between $110 million and $130 million as we continue the drilling campaign in Gabon, we complete the FPSO refurbishment and begin drilling additional wells in Egypt.

George outlined the multiple programs across our assets as we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future. Our second quarter guidance includes about $6 million in capitalized interest, all of which relates to our large capital investment program this year.

Even though we are adding a drilling rig in Egypt and increasing our 2026 production and sales volumes, our full year capital guidance for 2026 remains unchanged. In closing, while Q1 results were impacted by several factors, we are optimistic about improvement in Q2 and for the remainder of 2026 as we expect to continue to grow production and sales volumes. We believe we remain well positioned to continue executing on our strategy of growing production and reserves while adding meaningful value.

We have a long track record of successfully delivering operational results that meet or exceed expectations. We've achieved many things these past few years, and 2026 started with a strong operational successes. We've delivered in the past, and we're very well positioned to continue to execute at a high level across our diversified assets over the next several years. With that, I'll now turn the call back over to George.

Thanks, Ron. Our second quarter is off to a strong start with the drilling success at Gabon and the FPSO at Cote d'Ivoire back on location with production expected to restart at Baobab in June. In the first quarter, we rationalized our portfolio by selling the Canadian operations and added high upside opportunities at Kossipo and Cote d'Ivoire.

Looking across our asset base, we are executing on several projects across our expanded portfolio. In Gabon, we have an extensive drilling campaign underway, and the rig is now in a Ebouri drilling wells and looking to do workover that should add reserves and production. At Baobab, a couple of months after the field comes back online, we're expecting to begin a multi-well development drilling program.

At Kossipo, we are very excited to be named operator with a 60% working interest and are working on a field development plan that is being driven by new seismic, and we are looking to utilize existing infrastructure already in place. Also in Cote d'Ivoire, we are acquiring additional regional well data, licensing seismic data and concluding further geological evaluations of our new exploration block CL-705, where we're the operator with a 70% working interest.

In Egypt, our ongoing production optimization, workover and recompletion programs have performed well, and we are drilling additional wells in 2026, as I discussed earlier. In Equatorial Guinea, we have completed our initial front-end engineering and design study and confirm the viability of the development concept and are currently evaluating alternative technical solutions, which may deliver enhanced economic value.

Our ability to remain focused on successfully executing our strategy is key to growing the company profitably over the remainder of the decade. We have successfully delivered strong operational and financial results for the past several years where we have met or exceeded guidance on a quarterly basis, and we believe that we can continue to meet or exceed our guidance numbers in Q2 and beyond.

There are numerous macro events that we cannot control, but the things that we can control like operating efficiently, investing prudently and maximizing our production will help us deliver the forecasted growth and profitability for our shareholders and partners.

The timing of the new wells in our Gabon program recently coming online and the expected restart of Cote d'Ivoire later this quarter are certainly very well timed with the increase we're seeing in oil prices. Our entire organization is actively working to deliver strong results that will continue to help fund our capital programs while also returning value to our shareholders through a top quartile dividend.

We have maintained credibility over the past several years, having delivered on our commitments to the market and to our shareholders, and we will continue to deliver with these exciting slate of projects we have over the next few years. We are in an enviable position with a much stronger and diverse portfolio of producing assets with expected significant future upside potential. Thank you. And with that, operator, we are ready to take questions.

[Operator Instructions] Our first question here will come from Stephane Foucaud with Auctus Advisors.

My question is really around realization. So we are hearing those wild premium in the market versus Brent. I heard recently that some lifting in Nigeria were sold at a $15 premium to dated Brent, which is already at a premium on the N+1 prices. So I was wondering, is that -- is it what you see across your portfolio in Gabon and Egypt?

And then related to that, some of the production you have is hedged, but I assume that this hedging is around Brent. So that still allows you to capture even on that hedge production, any potential premium. If you could confirm if my understanding is right.

Stephane, it's Ron. Yes, you are correct. I mean, obviously, we saw at times a difference between the screen price and what we saw in dated Brent. But we had 2 liftings that are coming up. I can talk to them, April and in May. And in both occasions, we're seeing about a $4 premium to dated Brent for our crude.

So yes, we are seeing a premium for African oil at this point in time. Egypt is a more difficult one because it's domestically sold. But obviously, the listed price in relation to that, that were marked over from EGPC is getting closer to obviously dated Brent. So not necessarily seeing the premium develop there per se, but we've certainly seen it on the West African barrels. And it's obviously far too soon on CDI. We won't have a lift in CDI until about April -- sorry, August.

And with regards to the hedging?

With regards to the hedging, can you repeat what that question was again?

Well, my question was that I assume the hedging of financial hedging, which is basically are based on Brent.

Yes, we do because it is on dated Brent. So you're quite right. Any premium to that will be above what we've got our hedges in place at.

And our next question will come from Jeff Robertson with Water Tower Research.

Ron, could you share any additional color on the lifting schedules in Gabon and Cote d'Ivoire beyond the second quarter?

We can certainly share in the second quarter, we've got 2 confirmed liftings in Gabon. We're working with a partner in CNR for Baobab, but we likely see a lift in there in August time period. We basically have stated that we'll have one every other month in Gabon between now and the end of the year. And as we stated previously, there's not going to be another -- well, we don't foresee another GOC lift this year. So it's all contractor party lift. So hopefully, that helps you with your modeling there.

George, at Kossipo, if you get the field development plan submitted before year-end, what will that do to VAALCO's ability to shift reserves from one category to another?

Yes. I mean if we get the FDP in place before year-end, which is our commitment to the DGH in Cote d'Ivoire, basically, these characterizations of the 102 million barrel equivalent is currently sitting in 2C. That would put it to a 2P characterization within our NSAI report for year-end. So that's definitely a focus. That would add on to our 2P reserve books somewhere in the region of just north of 60 million barrels.

And our next question will come from Charlie Sharp with Canaccord.

Just another bit of a follow-up, if I may, on liftings, and that's been very helpful in terms of the timing of those liftings. I guess, can you remind me what the typical lifting size is in Gabon, what the anticipated typical lifting would be -- size would be in -- on Baobab? And also just on your production guidance for Cote d'Ivoire, are you -- does your guidance capture any potential flush production? Or would that be potentially on top of guidance?

Okay. Well, I'll start with the liftings then, Charlie. Typically, we -- in the past, in Gabon, we've lifted sort of parcel sizes of 650,000 gross. But as of late, we've tried to maximize that out to 900,000. That obviously, from an economics point of view and the freight makes it more beneficial for us.

So we are planning 900,000 gross lifts. In CDI, we generally plan 650,000 lifts, but we are working with the operator there to try and encourage higher lifts than that. Obviously, the vessels come back is in very good shape. And there's no -- certainly, in my mind, there's no reason why we can't be looking at sort of 900,000 to 950,000 lifts.

I'll add to what Ron said there, Charlie. One of the reasons we were with the operator down at 600 is the initial plan when the vessel came back on stream was not to use the wing tanks. That plan has subsequently been changed, and we're just finalizing some remedial work on site on the wing tanks right now to make sure we have that additional storage.

So that means that where before we had perhaps used those partly for ballast, but now can be used for storage capacity. And that starts to increase the argument around the higher liftings from Baobab.

With regard to the guidance, of course, we work closely with the operator when it comes down to the production forecast. We have our own simulation models that we work on the Baobab field and where we see the performance. You're absolutely correct that with the field shut in for some 14 months, we would expect to see flush production. We haven't put all this anticipated flush production upside into our guidance.

And there's really 2 reasons for that. One, we are confident in the history maps in our model that we have that what we're seeing indicatively of a kick start in production will be achieved, but we'll hold that in reserve right now. The second reason is unlike, for instance, at Etame, there's not a natural pressure support inside the Baobab field that requires water injection in order to sweep that oil up to the drainage points. So the water injection has also been, as you know, shut down during this period. So we're -- on the start-up sequence, we would expect the water injection to begin, and we do expect to see flush production, but we've kept that in reserve at the moment.

And our next question will come from Chris Wheaton with Stifel.

Two questions, if I may, guys. Firstly, Ron, a question for you on working capital, if I may. I was surprised at the magnitude of the working capital outflow in first quarter, particularly when my reading of the accounts is that the -- and you look at the difference between sales and production volumes that the Gabon cargo wasn't -- sorry, the Gabon cargo to pay the government taxes was already taken out of the revenue line.

So I wonder if you could help unpick that there for me because it feels like I've double counted somewhere or there's been double counting somewhere of both the Gabon tax revenue and also working capital outflow. And my second question was for George, on Kossipo, it's fantastic to see that head towards FID. Is the development plan presumably monetization via some of the Baobab infrastructure? In that case, has a sort of commercial framework been agreed with CNRL's operators so that that can form part of the sort of the financial framework that goes into assessing the project viability. Those are my 2 questions.

Chris, it's Ron. So I'll go first on working capital. On working capital in relation to the tax position, obviously, when we accrue up the barrels that are on the balance sheet as a liability for foreign taxes payable, Chris. So -- when we settle those, effectively, you're moving the working capital because there's an outflow of cash as you take those barrels off and settle them against that liability. So that did happen in Q1.

Also, our accounts payable came down a bit as we settled as along with the CNR, a number of the bills on MV10 when it came out of sail there to Dubai and came back into the African water.

So there was a movement in payables there as those bills were settled. And we completed a well in Gabon as well. And obviously, you've got the payments going out for that for Borr drilling too. So those were the kind of key catalysts. The other part is there is an inventory build as you go to the latter half of the quarter. The GOC lifted that early February and the partner lift was in April. So again, inventory built up a little bit. And with the strong prices, AR built up, although we collected most of the AR. So overall, that's where the outflow came. Against that, obviously, the unrealized hedges now has moved up the accrued liability number.

And I'll take the question on Kossipo, Chris. So it's maybe not well known, but even though we are the operator now of Kossipo in that economic extraction area, we're still under the single PSC. And within that PSC, any of the developments that are attached to CI-40 has a contractual right to evacuate back through the existing infrastructure. So that is very much clearly there.

With regard to the economics for coming through processing and storing through Baobab, that still has to be worked out, but it's worth pointing out as well that we are also 30% participants in that position and have a voice at that table on both sides effectively.

That all being said, when we're looking at the FDP, we've got to look at what is the most efficient extraction. We're 8 clicks away from Baobab. So either an interconnect or tieback solution and how does that look both from a capital spend and an engineering concept or there's also the opportunity to look at a stand-alone position if that is more economically efficient and more importantly, can be done in a more timely manner. But I think all the listeners should be -- take comfort that we have absolute contractual rights to evacuate through Baobab and maximize the efficiency of that facility if the timing allows.

And our next question will come from Bill Dezellem from Tieton Capital.

Two questions related to production. First of all, production in the first quarter was quite good relative to your guidance that you gave. Ultimately, what went right for that to come in so strong relative to guidance?

Okay. There's 2 things there. One, as we mentioned, I guess, back in March, we kind of intimated that the upward trajectory on production coming out of the Egyptian campaign in December meant we had a very strong profile coming into January and February.

And part of that -- so that was a big delta in our production upside. And also because of the performance, particularly around the final wells in the Egyptian campaign really led towards the acceleration of the campaign for 2026, pulling it forward from effectively a late Q3, Q4 prospectivity that we had kind of in a contingent to a firm program coming into May.

So that really changed our position on pulling forward the activity in Egypt because of the strong performance that came through in December and into first and second quarters. In addition to that, we did see obviously a little bit of a kick coming from the performance in Gabon. It continued to be more or less just above guidance from the [indiscernible] wells, and we obviously have the 2 new wells coming on in the drilling campaign. So -- but primarily, the kick against our forecast was coming in from [indiscernible]

Okay. And then relative to the 14H well, the upper part of that well that came in at really quite high production rate. Does the knowledge of that level of production lead to some learnings or a change in how you are thinking about future drilling in that area?

Yes and no is the answer to that. I think it's worth reminding everyone, we've been drilling and producing out of Etame for some 24 years now. So it's a very mature field. So when you look at -- when we talk about and in the announcements we talk about and the targeted drilling that we're going for, we talk about the concept of going after attic oil.

And what that actually means is we're looking at the positions where the existing drainage points are down dip of the upward parts of the structure, and we're trying to place these wells at the very top part of the structure to capture that additional oil that hasn't been swept by previous wells.

So you're correct in your assessment there that our well design is always looking to come across with an extended lateral at the very top of the structure to gather that attic oil that's never going to be swept from the existing drilling points. It's exactly the same type of well that we're trying to drill right now in the Ebouri with exactly the same type of concept. And all future wells, I believe, in Etame will be this type of well design, top of the structure, very long lateral, very long exposure to the reservoir in order to capture those stranded oil opportunities.

Bill, I'll just add a little bit more color to what George said there. I mean, as you saw, we increased the production and sales guidance from our Q4 call. And that's primarily with a view on that Main Fault Block well, which came in very well as the continued Egyptian success that we've got. So that's where the rise in the production and the sales is on the full year guidance.

Good luck with finishing the FPSO.

Our next question is a follow-up from Stephane Foucaud with Auctus Advisors.

Actually, Bill asked the question I wanted to ask, and I could not confirm it. That was around what had driven the production guidance increase in '26 in Gabon, but I think Ron just responded to that saying that this was basically the very strong well in Q1.

And our next question is a follow-up from Jeff Robertson with Water Tower Research.

George, at Niosi and also at your 2 blocks in Gabon, what's the earliest you might expect to see wells drilled there if you continue down that path?

Okay. So on these blocks, we -- if you recall, when we acquired these along with BW Energy and Panoro, the commitment position on these blocks was basically seismic acquisition, processing interpretation and one -- a single well commitment. So had we been a little bit ahead of the game, we could have thought of tagging on that single well commitment at the end of this campaign in Gabon.

We're definitely not going to be there because the acquisition obviously just completed in mid-January, and set for interpretation -- for processing and interpretation. We're not even expecting hot shot data probably into Q3, maybe as late as Q4 for the evaluation.

So as I think has been announced by BW Energy, they've picked up a rig to commence a program in later this year in Gabon. That program for them, I believe, runs through mid '27. So there's an opportunity that commitment well subject to interpretation and identification of a targeted location could come in late '27, early '28 at the back end of that program. Filling that, it's then going to be going to looking at the next opportunity for a rig to be in the area to meet that commitment on the drilling program.

And at Niosi, if you move to the second exploration phase, which I think will begin, I guess, at the end of this year. I think you have that might include a well by 2028. Is that -- would that likely be a 2028 well? Or could that slip into '27?

It's unlikely to slip into '27. It depends on 2 key things. One, the location of the well. So I firmly believe because you got to look backwards into VAALCO's history and you look backwards and these blocks that have been reassigned to us and our partners are areas that VAALCO previously held back in the early teens. So we do have an understanding of the prospectivity of that block, and that's why we were quite comfortable to come back in, in a partnership because we do see a degree of prospectivity there.

Now as to when and where that well will ultimately be drilled is down to, one, the location of the well and its proximity to infrastructure and the closer to our infrastructure or their infrastructure, obviously, makes it more exciting for us to pull that forward because it's a much closer monetization point. So that's really what's going to be the driver is how exciting is the prospects that we find and the location of these prospects to existing infrastructure, the closer they are, the more keen we would be to drill them. So it's unlikely in my mind, but it's never -- never say never that it would be falling into 2027, but there is that slight possibility.

And our next question will come from Jamie Wilen with Wilen Investment.

You guys have a lot of moving parts, which I'd like to tie together. As you exit 2026, will your barrels per day production approach 30,000 barrels?

Yes. Jamie, it's Ron. Our guidance at the moment has an exit rate of between 25,000 and 27,000 barrels. And obviously, we'll continue to look at that with the Gabon drilling successes as we go forward. And obviously, CDI, we've previously stated we're go into a batch drilling there, and we only see one of those wells completing, and that will be very late on in the year. So it will come in for 1 month. So if there's movement there, there's a possibility for that exit rate to be higher than that. But at this point in time, we're guiding an exit rate of between 25,000 and 27,000 barrels.

The only thing I'd add to that, Jamie, is, as I said earlier in the call, there's all kinds of possibilities of first production coming on CDI when we start it up. That's currently not within our guidance.

Okay. And secondly, as far as taxes go, in 2026 and '27. We have a lot of cost of oil that will go to limit our tax liability. How much free cash flow will we have that will not be taxable as we look forward?

I can't give you specifics on free cash flow. It's not taxable. What I can say to you, Jamie, is you've been in this for some considerable time. So you know the history here. In relation to the cost pools building up, we basically see for Gabon, as I say, there will be no other GOC state lift this year. I can't see a state lift now, and my team can't see a state lift now on the volumetrics until Q1 2027.

So again, there's not a cash tax liability in relation to that. We also foresee with the spend that we've got both for the Baobab and Ebouri for the drilling campaign in CDI, we think that will maximize that cost pool for about like 2-year period, but it really depends on oil price. If oil prices stay at this current level of $100, you will burn through those cost pools quicker. And that's the same case for Gabon. It's great that we will have incremental free cash flow from that from the pricing. It also mean we'll burn through it, but we won't have that tax expense. So what you'll do is you'll crystallize that benefit to the company quicker than our models predict at the moment, which our models have forward curve in there.

Not a bad thing at all.

And this concludes our question-and-answer session. I'd like to turn the conference back over to George Maxwell for any closing remarks.

Thank you, operator. I'd just like to thank everyone for participating in today's call. Obviously, we've had a considerable amount of activity. And I think, as Jamie mentioned in his last question, we've got a lot of moving parts. We've got a lot of catalysts that are happening throughout 2026. By the time we get to midyear, we'll have 3 drilling campaigns fully active in our assets, producing wells -- sorry, drilling wells and enhancing production. So again, catalyst to generating cash flow. So we've got a very, very busy year ahead. And that busy year is building both the profiles and the opportunity for significant steps up in production in early 2027.

But I don't want to look that far ahead because we only need to look as far ahead as Q2 when we start to see the increase in the crude oil sales coming from liftings and those liftings are increasing even more with the additional production that we're taking in Gabon from the drilling campaign and the restart of the Baobab field. We've seen Egypt operating very successfully from the last campaign in Q4 2025. We made that decision to accelerate the program in 2026 to further enhance those opportunities.

So as you can see, that -- and then we've got our developing assets in Kossipo, we didn't talk much about Equatorial Guinea, but I'll just highlight again, we're going to FID for Equatorial Guinea this year. And so we're building the portfolio to continue that step change in production going into '27 and '28.

So with that, I'd like to thank everyone for participating. I look forward to talking to you in the Q2 call in August. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.

Good morning, and welcome to the VAALCO Energy Fourth Quarter and Full Year 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, operator, and welcome to VAALCO Energy's Fourth Quarter and Full Year 2025 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the fourth quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. [Operator Instructions] I'd like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparison and guidance that should be helpful.

With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements within the meaning of federal securities laws. As a reminder, these statements are based upon our current beliefs, as well as certain assumptions and information currently available to us as we discuss in more detail in our fourth quarter and year-end 2025 earnings release and our Form 10-K for the year ended 2025 we expect to file on and before March 16, 2026. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and the reports we file with the SEC, including our Form 10-K.

We will also refer to certain non-GAAP financial measures, including adjusted EBITDAX, whose reconciliation you will find in the fourth quarter and year-end 2025 earnings release and in our slide deck. Please note that this conference call is being recorded, and let me turn the call over to George.

Thank you, Al. Good morning, everyone, and welcome to our fourth quarter and full year 2025 Earnings Conference Call. Over the past 3 years, we have delivered outstanding operational and financial results, including generating over $750 million in adjusted EBITDAX while meeting or exceeding our quarterly guidance targets. Maintaining operational excellence and consistent production across our portfolio is essential to increasing our adjusted EBITDAX, which has allowed us to expand our portfolio and also to fund organic growth initiatives, better positioning VAALCO for the future.

We recently divested all of our Canadian assets, and we added to our Cote d'Ivoire position by being named operator with a 60% working interest in the Kossipo field on Block CI-40. Last year, we added an exploration block, CI-705, in Cote d'Ivoire and are working with our partners on the seismic acquisition and processing at Niosi Marin and Guduma Marin blocks, offshore Gabon. In addition, we drilled our first exploration well in Gabon since 2013 during Q1 2026. And although unsuccessful, combined with the new exploration portfolio in Gabon and CDI, we have created a more balanced portfolio between production, development and high-quality prospective assets.

We have accomplished many things in these past 5 years, growing VAALCO from a single asset delivering around 5,000 barrels a day to a diversified multi-country operator well on our way to achieving our goal of 50,000 barrels of oil equivalent per day. We have, over the past several years, in addition to growing production, reserves and adjusted EBITDAX, has been a sustained commitment to returning cash to shareholders. In 2025, we returned another $26.5 million in dividends since Q4 2021. We have returned over $150 million to our shareholders through dividends and share buybacks.

As we discuss our operational and financial results today, it is important to remember that 2025 was a transitional year for VAALCO as production came off-line in Q1 at Cote d'Ivoire due to the FPSO project, and we did not start the drilling campaign in Gabon until late Q4. This means that the meaningful production uplift we are projecting from these major projects won't begin until later this year and into 2027.

I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire. I'd like to remind you that we had no production or interest in Cote d'Ivoire prior to April 2024, when we made the Svenska acquisition, securing a valuable asset with Baobab on the CI-40 block. In line with the project time line, the FPSO at Baobab ceased hydrocarbon operations as scheduled on January 31, 2025, with the final lifting of crude from the vessel occurring in early February. The vessel departed from the field in late March and arrived in the shipyard in Dubai ahead of schedule in mid-May 2025. The FPSO refurbishment went very well, and the FPSO departed Dubai in early February 2026 and [ look ] back to Cote d'Ivoire. The vessel is currently off the coast of South Africa and continues to be on track to return to Baobab, with the field restarting in Q2 2026.

Significant development drilling is expected to begin later this year after the FPSO returns to service with a drilling program which includes 3 producers, 2 to 3 injectors and 2 workovers providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension to the license to 2038. The current drilling plan on Baobab is to begin drilling on a batch basis, the top-hole sections of all 5 wells. The completions will then be commenced, and we expect at least 1 well to be on full production by year-end.

In March 2025, we announced a farm-in agreement for the CI-705 block offshore Cote d'Ivoire, where we will operate with a 70% working interest and a 100% paying interest through the seismic reprocessing and interpretation stages and potentially drilling up to 2 exploration wells. The block is favorably located in a proven hydrocarbon system and is approximately 70 kilometers to the west of our CI-40 block, which contains 1.2 billion barrels of oil equivalent of [ STIP ]. We received seismic data for the block, and we are conducting a detailed integrated geological analysis to assess and mature our understanding of the block's overall prospectivity, as well as the basin's overall potential.

In accordance with the CI-40 PSC, VAALCO and PetroCI elected [ a sole risk ] development of the Kossipo field. In February 2026, VAALCO was confirmed as operator with a 60% working interest in the Kossipo field on the CI-40 block, just 8 kilometers from Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help derisk and enhance our evaluation and development plan.

The Kossipo field was discovered in 2002 with the Kossipo-1X well and later appraised in 2019 with the Kossipo-2A well, which tested at over 7,000 barrels of oil per day. Our current assessment has a field with an estimated gross 2C resources of approximately 102 million barrels of oil equivalent and 293 million of barrel of oil equivalent in place. So in less than 2 years, we have established a sizable position in Cote d'Ivoire with considerable upside potential to help us achieve our production growth targets in a significant and high-demand hydrocarbon basin. We have demonstrated our ability to acquire, develop and enhance value through accretive acquisitions, and we are excited about the prospects in Cote d'Ivoire.

Moving to Gabon. Given that we haven't drilled a well in Gabon in over 3 years, we are pleased with the overall positive production results we saw in 2025. In July 2025, we successfully completed a planned full field maintenance shutdown of the Gabon platforms to perform safety inspections and necessary maintenance. This is the first time that we have had to perform a full field shutdown at Gabon since the FSO was brought online in 2022.

In the fourth quarter of 2025, we've begun our Phase III drilling program in Gabon with the drilling of 2 pilot wells in the Etame field. Based on the pilot well results, we proceeded with the drilling of the Etame 15H-ST development well on the [ 1V Block ] of Etame in December 2025. The rig remained on the Etame platform to drill an exploration prospect in West Etame. While the well encountered 10 meters of high-quality Gamba [ sands ], the target zone was water bearing and not commercial. The lower portion of the well will be plugged and abandoned, but the wellbore will be utilized as sidetrack in the upper portion of the well to drill the ET-14H development well in the main fault block of Etame that was derisked from the results of the earlier pilot wells.

When we committed to drilling the Etame West exploration well, we knew there was geological risk of not encountering commercial sands, but the size of the potential resource made it a risk worth taking. Furthermore, we purposely designed the well so we could still utilize the wellbore to drill a development well into a nonproductive area if the sands were not commercial. We are now working to drill the sidetrack well, which should be completed in April. After completing our program at the Etame platform, we expect to move the drill rig to the SEENT and Ebouri platforms, where we have several wells and workovers planned to enhance production, lower cost and potentially add reserves.

Regarding our exploration blocks in Gabon, the Niosi Marin and Guduma Marin, we are working with our partners and the operator on plans for the 2 blocks moving forward. We commenced a seismic survey in November of 2025, which was completed in the first quarter of 2026. This survey completed part of the exploration work program commitment for these blocks. Further evaluation and interpretation of the results are expected to continue into the second and third quarters of 2026. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks.

Turning to Egypt. For the past year, we had contracted a rig and drilled 20 wells across a drilling campaign that helped to increase production year-over-year in 2025. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. We have been able to drill 8 extra wells faster and cheaper than what we had budgeted for the same amount of capital, which has also positively impacted production.

In conjunction with our drilling program, we also continue to perform production optimizations, workovers and recompletions that have significantly improved our production performance. While we wrapped up the drilling program in the fourth quarter of 2025, the very good results drilled at the end of the year have resulted in Q1 2026 producing consistently above 11,000 barrels of oil per day and well above our budget of 10,700 barrels of oil per day. We plan to continue optimization, workovers and recompletions in 2026 focused on production enhancement, where we finalize our development and exploration opportunities for the upcoming drilling campaign.

In the Western Desert, work is ongoing to evaluate and integrate the results of our last exploration well in South Ghazalat. This well has confirmed the presence of both oil and gas. The long-term test and pressure monitoring that we have carried out has confirmed the connection of the oil bearing zone to a larger volume. Based on this, we are updating our subsurface mapping, prospective evaluation and volume estimation in order to put together the appropriate economic field development plan for our acreage. We are particularly pleased with the progress our team made in our Egyptian receivables in 2025. Ron will discuss this in more detail, but we are now essentially on a current billing basis with EGPC.

On February 5, 2026, we announced an agreement for the sale of all of our Canadian assets to a third party for approximately $25.5 million, which equates to 2.7x our trailing 12 months operational cash flow. The Canadian properties were producing approximately 1,850 barrels of oil per day at the time of sale, and the sale closed in February 2026 as expected.

As Ron reviews our production guidance for 2026, keep in mind that our first quarter and full year 2026 results will only include January and a prorated February through the 19th, Canadian production and financial results. We believe we had extracted significant volume from the Canadian assets, including almost $65 million in operating cash flow since their acquisition. While we believe the Canadian assets are solid, we decided to focus on our core assets under significant upside potential. With all of the large-scale drilling campaigns underway or planned in those areas, we determined that now was the right time to sell.

Turning to Equatorial Guinea. In March 2024, we announced the finalization documents of the Equatorial Guinea related to the Venus Block P plan of development. Last summer, we began our Front-End Engineering Design, or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risks and challenges on the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which would also significantly simplify the drilling operations and well design, and this evaluation is currently underway. We are excited to proceed with our plans to develop, operate and begin producing from the discovery in Block P offshore Equatorial Guinea in the next few years.

Before I turn the call over to Ron, I would like to highlight some positives with our 2025 year-end reserve results. Our SEC reserves were prepared by NSAI, an independent third-party engineering firm that has provided annual independent estimates of VAALCO's year-end SEC reserves for over 16 years. While SEC proved reserves at year-end decreased modestly year-over-year by 5% to 43 million barrels of oil equivalent, we did see 4 million barrels of oil equivalent of positive revisions, additions and extensions, which replaced 2/3 of our 2025 production of 6 million barrels of oil equivalent. Also with the Phase III drilling program in Gabon starting near the end of 2025 and the FPSO returning and drilling at Baobab starting in 2026, we expect to see more additions and extensions related to our organic drilling program in 2026 and 2027.

Additionally, despite lower average SEC pricing of around $70 per barrel, our SEC proved reserve PV-10 increased 8% from $379 million to $410 million due to positive revisions, offset by widening differentials in Gabon and a decrease in year-over-year SEC prices. Year-end 2025 SEC reserves included a 17.5 million barrel oil equivalent in proved developed reserves and 25.5 million barrels of oil equivalent in proved undeveloped reserves.

Turning to a 2P CPR estimate, which includes proven and probable reserves using VAALCO's management's assumptions for future pricing and costs reported on a working interest basis prior to deduction of government royalties, we also saw a small year-over-year decrease of 6% to 73.7 million barrels of oil equivalent. Despite this, the 2P CPR and PV-10 saw a 26% increase to $859 million at year-end 2025. We have a strong runway of opportunities that will continue to add value. And as you can see from our SEC proved reserve, 2P CPR reserves and corresponding PV-10 values compared to our current market cap, our stock price remains undervalued.

In closing, we have an outstanding diversified portfolio of assets that have significant upside opportunities. We remain focused on growing production, reserves and value for our shareholders. I'd like to thank our hardworking team who continue to operate and execute our plans. Over the past several years, we have significantly diversified our portfolio, enhancing our capacity to generate operational cash flow and adjusted EBITDAX while returning capital to shareholders and increasing our credit facility capacity. We are well positioned to execute the projects in our enhanced portfolio and our proven track record of success these past few years [ to do so ] confidence for our future.

With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George, and good morning, everyone. I will provide some insight into the drivers for our financial results, with a focus on the key points and give additional insight into our 2026 Q1 and full year guidance.

Let me first echo George's comments about our continued success and our ongoing ability to meet or exceed our quarterly and annual sales, production and cost guidance, leading to consistent operational and financial results. I want to remind you that in 2025 and midyear, we increased the midpoint of our full year production and sales guidance. Even with these higher targets, we were able to deliver 17,452 net revenue interest barrels of oil equivalent per day of sales in 2025, above the high end of our increased guidance. We also delivered production of 16,556 net revenue interest barrel of oil equivalent per day, or 21,160 working interest barrels of oil equivalent per day, both above the midpoint of VAALCO's increased guidance. These strong sales numbers helped us generate adjusted EBITDAX of $173.4 million and net cash from operating activities of $212.7 million for the full year of 2025.

In the fourth quarter, we reported a net loss of $58.6 million or $0.56 per diluted share, which was driven primarily by a noncash impairment charge of $67.2 million due to the sale of our Canadian assets. This impacted our full year net income, as well as pushing it into a net loss. After generating $17.2 million of net income in the first 9 months of 2025, we ended the year with a net loss of $41.4 million driven by the fourth quarter and the noncash impairment charge.

Turning to costs. Our production costs for 2025 were in line with guidance, both on an absolute basis and on a per barrel basis. With the lower sales in 2025, we were down on an absolute basis, but slightly higher on a per barrel basis year-over-year. For the full year 2025, absolute expense was $158 million, and on a per barrel basis was $24.89. For the full year 2024, while the absolute costs were up by about $10 million, our per barrel costs were slightly lower at $22.48. Cash G&A costs were below the low end of guidance for the fourth quarter and for the full year 2025.

Our focus remains on keeping our costs low to enable us to maximize margins and increase our cash flow. Exploration expense for the fourth quarter was $6 million and was primarily attributable to the purchase of 3D seismic costs associated with Niosi and Guduma blocks in Gabon as well as costs associated with an Egyptian exploration well in South Ghazalat determined to be currently not commercially viable. The well confirmed the presence of hydrocarbons, and the team are updating their mapping, prospect evaluation and volume estimation in order to put together the appropriate economic field development plan to present to both our partner and the state.

Moving to taxes. In the fourth quarter, we reported an income tax benefit of $4.6 million, which is comprised of a $5.2 million current tax expense, offset by a deferred tax benefit of $9.8 million. Income tax benefit includes a $7.3 million favorable oil price adjustment as a result of the change in the value of the government of Gabon's allocation of profit oil between the time it was produced and the time it was taken in kind.

For the full year 2025, income tax expense was $14.8 million, which included a deferred tax benefit of $29.4 million. As I've previously stated, in Gabon, Egypt and Cote d'Ivoire, our foreign income taxes are settled by the government through oil liftings in Gabon and Cote d'Ivoire and the government taking their share in Egypt.

Turning now to the balance sheet and our cash flow statement. Unrestricted cash at the end of the fourth quarter increased by nearly $35 million to $58.9 million at December 31, 2025, while continuing to fund VAALCO's capital program with no draws against the company's RBL in the fourth quarter. We are particularly pleased with the progress our team has made in our Egyptian receivables in 2025. Collections from the Egyptian General Petroleum Corporation accelerated in 2025, and all of our aged receivables are now current. At the start of 2025, our outstanding accounts receivable for EGPC amounted to $113 million. And at year-end 2025, this balance had fallen to $31 million, even after invoicing over $129 million in revenue for the year. We've collected over $210 million in 2025, boosted by an industry payment of $40 million received in the last week of the year. Additionally, we continue to see collections exceeding revenue through quarter 1 of 2026.

In 2025, we entered into a new reserves-based lending facility with an initial commitment of $190 million and the ability to grow to $300 million. The facility has a current commitment level of $255 million and only $60 million drawn at year-end 2025. This facility is helping to supplement our internally generated cash flow and cash balance to fund our capital programs in Gabon and Cote d'Ivoire. As expected, during the first quarter of 2026, we expect to make additional draws against our RBL for our 2026 capital program. We anticipate a substantial part of the interest we incurred this year will be capitalized and have been taken into our capital guidance.

In Q4 2025, VAALCO paid a quarterly cash dividend of $0.0625 per common share or $6.5 million. And in 2025, we returned $26.5 million to shareholders through dividends. We also announced the first dividend payment of 2026, which will be paid later this month.

Turning to hedging. Earlier this year, prior to the Iran conflict, we saw opportunities to get better pricing for our hedging portfolio and took advantage of the market at that time. We were able to secure collars that have a floor of about $65 per barrel for the balance of 2026 for about 50% of our production with ceilings as high as the market allowed when the hedges were put in place. The market is very volatile right now, but we will continue to monitor the situation and hedge on any geopolitical shock or spike where we can. Our full quarterly hedge positions are disclosed in the earnings release.

Let me now turn to guidance, where I'll give you some key highlights and updates. I want to remind you that guidance for 2026 has the Canadian assets for only a portion of the first quarter, with the sale closing in the middle of February, and we are forecasting the Baobab field in Cote d'Ivoire coming back online in Q2. So there are some ups and downs in production and sales for the first half of 2026, but we expect both to increase materially in the second half of 2026 when the FPSO is back online and the full impact of the Gabon drilling campaign is realized.

Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with our production breakout of both working interest and net revenue interest by asset area. For the total company, we are forecasting Q1 2026 production to be between 18,700 and 20,600 working interest barrels of oil equivalent per day and between 14,200 and 16,000 net revenue interest barrels of oil equivalent per day. This takes into account the Canadian asset sale, the continued FPSO project in natural decline.

We expect our first quarter 2026 net revenue interest sales volumes to range between 11,200 and 12,900 barrels of oil equivalent per day. For the full year 2026, we are forecasting a production range for the total company to be between 20,100 and 22,400 working interest barrels of oil equivalent per day and between 16,100 and 17,950 net revenue interest barrels of oil equivalent per day. Our expected full year 2026 net revenue interest sales volumes are 14,900 to 18,050 barrels of oil equivalent per day.

For the first quarter, we are forecasting our sales to be lower than our production, driven by a single state lifting in Gabon. With a substantial capital and operational program in 2026 for Gabon, we forecast this state lift should be the only state lifting in 2026. We are projecting 5 optimized liftings in the year with the timing 1 every other month, beginning with April. We expect our absolute operating cost to be in line with 2025. And with our sales also in line with 2025, we are projecting our 2026 per barrel of oil expense to be in the range of $23.50 and $31 per net revenue interest barrels of oil equivalent. We are also expecting slightly higher absolute cash G&A in 2026.

For our exploration expense, taking into account the seismic work in Gabon and Cote d'Ivoire, along with the West Etame exploration well, we are forecasting exploration expense to be between $30 million and $35 million for 2026 with a midpoint of approximately $29 million for the first quarter, when we expect most of the expense to occur.

Finally, looking at CapEx. Our 2026 capital spend is projected to be between $290 million and $360 million as we continue the drilling campaign in Gabon, complete the FPSO refurbishment and begin drilling at the Baobab field in Cote d'Ivoire, continue recompletions in Egypt and begin spending in Kossipo. George outlined the multiple programs across our assets as we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future.

For the first quarter, we are expecting a range of between $90 million and $110 million for our CapEx. Our first quarter guidance includes about $3 million in capitalized interest, while the full year 2026 includes about $22 million to $24 million in capitalized interest, all of which relates to a large capital investment program this year.

In closing, we are well positioned to continue executing our strategy of growing production and reserves while adding meaningful value. We have a long track record of successfully delivering results that meet or exceed expectations. We've achieved many things these past few years, and 2026 looks like it will be another strong operational and financial year.

Despite all of this, we continue to trade at a low multiple of EBITDAX. And with a robust organic capital program of high-return growth opportunities, we are forecasting substantial increases in sales and adjusted EBITDAX in the future. We have delivered and very well positioned to continue to execute at a high level across our diversified assets over the next several years.

With that, I'll now turn the call back over to George.

Thanks, Ron. As you have heard this morning, we have successfully delivered strong operational and financial results for the past several years by successfully executing on our diversification and growth strategy. In these past 5 years, we have achieved so many milestones that reflect the efforts and hard work of our employees in making the company that you see today. We have successfully grown VAALCO from a single asset delivering around 5,000 barrels of oil per day to a diversified multi-country operator, well on our way to achieving our goal of 50,000 barrels of oil equivalent per day.

Our strategy remains unchanged: Operate efficiently, invest prudently, maximize our asset base and look for accretive opportunities. This continues to deliver for our shareholders, partners and all stakeholders in VAALCO Energy. We have rationalized our portfolio, adding high upside opportunities at good prices, and we are poised to deliver meaningful organic growth in the future.

Looking across our asset base, we have a multitude of projects to execute. In Gabon, we have an extensive drilling campaign underway at Etame that should add reserves and production. The FPSO at Baobab is nearly back in Cote d'Ivoire, and the field is expected to be back online in the next couple of months as we work with the operator on the 5-well development drilling program that is scheduled to begin later this year.

At Kossipo, we are very excited to be named operator with a 60% working interest, and we are working on a field development plan that is being driven by new seismic, and we're looking to utilize existing infrastructure already in place. Also in Cote d'Ivoire, we're acquiring additional regional well data, licensing seismic data and conduct further geological evaluations to our new exploration block, CI-705, where we are the operator with a 70% working interest.

In Egypt, we have an ongoing production optimization workover and recompletion program, and we're examining drilling additional wells. In Equatorial Guinea, we have completed the initial Front-End Engineering and Design study that confirm the viability of the development concept and are currently evaluating alternative technical solutions, which may deliver enhanced economic volume. Our entire organization is actively working to deliver sustainable growth and strong results to continue funding our capital programs while also returning value to our shareholders through our top-quartile dividend.

I believe we have gained credibility over the past 3 years, having delivered on our commitments to the market and to our shareholders, and we will continue to deliver with the exciting slate of projects we have over the next few years. We are in an enviable financial position with a much stronger and diverse portfolio of producing assets with significant future upside potential. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserves and cash flow has not been fully reflected in our stock price, but we believe we will see the market begin to properly value VAALCO as we execute on our organic opportunities over the next few years.

Thank you. And with that, operator, we're ready to take questions.

[Operator Instructions] Our first question today is from Stephane Foucaud with Auctus Advisors.

So I've got a question around CapEx in Cote d'Ivoire. And perhaps if you could provide a bit more granularity on how it is split? In other words, what is FPSO, what's drilling, what's maybe Kossipo? And start more importantly, how much CapEx you would expect or residual CapEx you would expect in '27 for this drilling program that you will start in '26 in Cote d'Ivoire? And I will have a follow up on Kossipo.

Thank you, Stephane. Well, obviously, the guidance we've been giving for Q1 and relating to the CapEx, the majority of that is split between the drilling program in Gabon and the hookup for the FPSO in Cote d'Ivoire. So at that point, we expect around about 50% of the CapEx will be for Q1 is linked to the Gabon drilling program, with the balance primarily being in the FPSO finalization and towards the hookup.

On Kossipo, for the full year, we're really -- the CapEx is kind of limited to just looking at preparation and development of the field development plan for submission. So that's really a limited amount of around $10 million. There's no -- until we get the field development plan in and approved, the future CapEx positions for Kossipo will then be established based on the approved field development plan.

And for the residual CapEx for drilling in Cote d'Ivoire in '27?

Yes. That is really down. And as I mentioned in my statement, we commenced the drilling in September with the back setting of the top hole section. And then we go into drill 1 well that we hope to have drilled and completed by late November in Q4. So the CapEx position for those batch drillings is going to be somewhere in the region of between $30 million and $45 million.

Remaining?

No, no. In Q4. In Q4. That would be our CapEx position for Q4 for that drilling program, the working interest for us.

I see. But then on those 6 wells and a few workovers you plan, there would be -- I'm just trying to equate what production we could be looking like with remaining CapEx in '27 for that program. So I assume there will be still some completion work to be due in '27? Won't there be? Will there be?

Absolutely. We've got a 5-well program. We only have 1 well down in production in '26. The other 4 wells, bottom hole sections will be drilled in 2027.

And injectors.

Yes. Sorry. Thor reminded me, we've also got 3 injectors to do as well.

I see. So assuming, say, [ 40 million ] per well gross, something like that?

No, we're probably closer to [indiscernible] per well gross. And obviously, we're 1/3 of that.

Yes. Okay. Okay. And my follow-up is a quick one is on Kossipo. So when would you see the big CapEx starting on Kossipo? Is that a '27 event, '28, later? I know first oil is in 2030.

It's going to be 2028. If you think of how we -- I mean, this is obviously a reasonable deepwater development, somewhere around 400, 500 meters of water depth. So when we get the field development plan, we're planning to have that submitted before the end of the year. One of the big issues here, if we can successfully get it submitted before the end of the year, that 2C contingent resource automatically drops into a 2P position for us on reserves. By the time we submit that plan and get it approved, we then can start the engineering phase, and the engineering phase will take probably at least between 6 to 12 months before we start any major CapEx commitments on equipment delivery. And obviously, at the same time, we then look to source a rig for the drilling activity.

We also have to look at the position of how we're going to develop this field. At the moment, there's the opportunity to tie back into Baobab. So if we're tying back into Baobab, then going to take consideration for suitable [ along ] and Baobab, the MV-10 production facilities. So it really is quite a -- we're looking at all the optionality right now as to how this fits in with the existing production profile of Baobab or if there's an accelerant opportunity on a stand-alone position on Kossipo, but that will all come out in the field development plan this year.

The next question is from Jeff Robertson with Water Tower Research.

Ron, a question on the guidance. Can you talk about the base spread price forecast that's embedded in the NRI volume assumptions? And then just given the extreme volatility in crude prices, can you provide a bit of a refresher on how that flows through the PSCs with respect to NRI volumes and cost recovery?

Yes, I can do that. Underlying Brent assumptions that we assumed for 2026 was a baseline of $65 for Brent. And obviously, we've got our differentials off of that. With regards to upside on that, obviously, the PSCs, the West Africa PSCs are very much a profit all split, so we benefit from the rise in prices to the extent we have the hedges in place.

Outside of that, Egypt, obviously, that PSC is somewhat very protective on lower oil prices. But on upper oil prices, the split between the excess cost or what goes to the government versus the contractor is 85% to the state, 15% to the contractor. So the upside is somewhat limited in relation to the Egyptian barrels, although there is upside, but very, very weighted towards the contractor on the West Africa side.

And a question on Kossipo, George. And I guess on CI-705 of as well. As you advance those projects, would you expect to maintain VAALCO's current working interest? Or at some point, do you -- would you get to a point where you'd consider trying to bring in another party to take a share of that risk?

Okay. On Kossipo, right now, we're more than comfortable at 60% working interest and operatorship, and we've got an excellent relationship with our partner, PetroCI. So at this point, that's not currently in our plans, a farm-down position. I mean, we have to bear in mind, we're looking at this opportunity as we mentioned in our releases that -- the appraisal well delivered over 7,000 barrels a day. So the size of the prize is very large for us.

So obviously, it's going to be based upon the ranking of our investment opportunities and what comes out of the field development plan. On that basis, if it does look like it's going to be a rather heavily punitive CapEx position or it's going to have an elongated time line, we do take account of how long we have to invest the dollar before it comes back out of the ground. And that may drive a different decision-making process than we have currently planned.

On CI-705, we have started an analysis on the prospectivity. We've -- we're working that up this year. We are very encouraged by what we see. What we have to bear in mind with CI-705 is that we have a block that's just under 2,500 square kilometers. It goes from the beach, right through into water depths of in excess of 1,000 to 1,500 meters. So depending on where we see the most attractive targets -- and we see targets right now at the 200-meter level and we see targets at the 1,300, 1,400-meter level. And it will really depend on which targets we want to exploit. Because obviously, the deeper we go, the more expensive it becomes. But if we're looking at the shallower targets as our first exploitation, I'm fairly confident we would keep that in-house. If it's a deeper target, then we'd certainly talk about outperforming out some of that position. So we share the risk.

The key here for us is we've built a position, as I mentioned earlier, in today's call in Cote d'Ivoire, a very hot area of activity, particularly by some of the IOCs, and we've got ourselves exceptionally well placed in those areas.

The next question is from Chris Wheaton with Stifel.

Two questions, if I may. Firstly, the roughly $150 million plus CapEx in Cote d'Ivoire this year. Could you help break that down between what's left on the FPSO reefer project and the recommissioning but then also the planned drilling later in the year? So the second question was on free cash flow and your uses of free cash flow. If prices stay elevated and you do get -- I won't use the word windfall for obvious reasons. You do get an extra $30 million to $40 million of, say, of free cash flow generated in the year. Where do you apply that? How much could you actually reinvest quickly? How much do you want to keep on balance sheet, given the volatility in prices and the fact -- and you've got a big CapEx program coming up? And how much might possibly be returned to shareholders? I'm interested in that sort of balance sheet sensitivity if you do get that -- higher free cash flows than originally planned for 2026. Those are my questions.

Okay. I'll take the CapEx [ line ] on the project. So as you know, the vessel is currently just rounding the Cape in South Africa. We've -- we're very pleased with the progress of that project. As you're all aware, the vessel sailed out of a rather hot area right now, right before those activities kicked off, and we're very pleased that the vessel was well clear of those areas in a timely manner.

With that, as we come around the Cape, we've got to [ back ] up on towards Ivory Coast. And at that point, we've got basically the hookup and recommissioning to do on the vessel. So our position on that from where we are with the project right now is probably around about $50 million of that would be our share between the hookup and the recommissioning and getting the anchor changed and everything down on the vessel, with the balance being on the top side holes and the completion of the first well.

Yes. It's Ron, Chris. On the free capital question, obviously, when we talk about pay down debt, I mean, if we've got more free cash flow than we're projecting this year, if oil prices remain high, my aspect on that would be that we would not draw down as much debt more than anything else. Effectively, we would use that cash to not draw on the facility.

So I don't think necessarily that we're looking to enhance the returns this year with our shareholders. We do have a high capital commitment. We're very much on track in these projects. And it's very much a story of growth in 2027. With the batch drilling, you're not going to see all of that production that CDI is going to give us until probably the end of Q1 into Q2 of next year. So very much the free cash flow incremental will be used effectively not to draw as much debt.

Okay. That's great. Can I just have one follow-up, please, which is on Equatorial Guinea. If you do achieve FID this year, so 4Q, which is what I think you've said, does that still leave you on track for first production by the end of 2028? Or does that slip into 2029, do you think?

I think currently on -- and I've got to be careful because we haven't got to the full technical evaluation. But now that we're trying to understand the benefits of a vertical solution rather than one off the shelf, when we look at what's available in the marketplace to execute that solution, I'm still pretty comfortable that we will still be on track as we outlined in our Capital Markets Day for Equatorial Guinea development and production.

The next question is from Charlie Sharp with Canaccord.

I hate to do this, but I'd like to go back to the CapEx, if I may, and ask the question in a slightly different way. There are so many moving parts that it's difficult, at least for me, to kind of grasp exactly where you are on that. And I guess the question, therefore, I have is in the [indiscernible] CMD, you indicated exactly what you expect to the cost of the FPSO refurbishment, the Baobab Phase 5 drilling and the Gabon drilling programs to be net to yourselves. Nearly a year on from there.

Can you quantify where those sit today and where the deltas are compared to what you said last year? And just also a little follow up on -- I think Stephane asked about the spillover, if you like, into '27. And you went through that in terms of [ Cote d'Ivoire ] drilling. [indiscernible] spill over of the program in Gabon into next year, do you think?

Okay, Charlie, it's Ron here. So I think to give a bit more color on the CapEx side of things. The Baobab Ivorian FPSO rebuild, we've kept it on schedule, as you know. Costs have increased in relation to the amount of steel work predominantly on that vessel. And I would say the gross costs that we've got predicted really for that with the operator is roughly about $80 million to $100 million higher than it was originally planned.

Of course, our share of that is 1/3.

Outside of that, the drilling is very much -- certainly from a CDI perspective, it's very much on what we said for the Capital Markets Day. In Gabon, obviously, we're a lot later in starting the program than we had expected when we did the Capital Markets Day back in May. That -- and we said it in the last call -- probably moved about $40 million to $50 million from 2025 into 2026. So there is a bit of a timing element there.

The CapEx is the CapEx. Obviously, we've got an exploration expense in relation to the West Etame well, which was an exploration. Effectively, it was water wet. So we'll have that expense in Q1 of 2026.

On your second part of the question, Charlie, is no, do we expect to see a rollover of the Gabon drilling program into 2027. That's an absolute no. We will have completed this program most likely in the early third quarter of 2026. And I thought Ron was mentioning on the exploration well, we -- I mean, that certainly has had a cash impact but not on the CapEx side. But I mean, when we look to the opportunity for that exploration well, it was definitely the right decision. And as I said earlier today, we optimize that well design to be able to reuse the top hole section to go back and drill the development well that we derisked on the pilots in December.

That's great. And one very short follow-up, if I may. Given the expectation for a second half weighted production uplift, could you give us some idea of where you see year-end '26 exit production at?

I think Ron has got the [ gains ], he's just looking at it now.

Charlie, again, we've only got the 1 well coming in from CDI in 2026 because obviously, they're batch drilling. But our working interest numbers will be somewhere between 25,000 and 26,000 barrels of oil equivalent on that exit rate.

The next question is from Bill Dezellem with Tieton Capital Management.

Let me start just from a big picture perspective with the Iran conflict. Is there any additional either advantage in any way to having your production in West Africa, specifically Gabon, at this point?

That's an easy one. Obviously, our routes to monetize the crude in the export markets remain uninhibited by that particular activity in that conflict. So the advantage you would actually see is that what you're seeing reflective in the spot pricing for crude. Now as you're aware, our crude is based on Brent spot pricing. We have, as Ron mentioned earlier today, we made sure we started to take advantage. And you've seen us do this many, many times in the previous years, but we do have heavy CapEx programs. We do go out and protect our cash flow positions as best we can on a cost [ of caller ] basis with the hedges.

So ahead of this conflict in the Middle East, we -- Ron had secured significant positions to protect our cash flow on the cost [ of callers ] through 2026 and into part of 2027. You can see that on our supplemental deck and on the earnings release. Anything out with that, obviously, we get and enjoy the upside of that. And that -- if the prices remain as high as they are at the moment, we will see additional cash coming in, in relation to particularly Gabon and the Ivory Coast production levels -- sorry, cash levels for the production.

And so there is no additional price advantage to your location? It's just simply availability that you have, availability to get the crude to Europe or whatever market?

Yes. I mean -- it's Ron again, Bill. We could see the premium going on to the Brent price for the type of crude that we've got. I mean, the Gabon Etame crude, it's had a discount to Brent in 2025. But in previous years, we have seen some premiums. So it would not be out of the question for that premium to come back in. The big question here is what's going to happen with freight prices with a prolonged situation in the Gulf. So that's a $64,000 question. I think we're all playing with is what freight is going to do for those vessels.

All right. And so you have not seen that premium return yet?

No. We saw the differential at one point. I think it was last week, we saw WTI and Brent virtually get parity. So the differentials are going to move. We just haven't seen the effect -- the long-term effect yet, Bill. So it's something we're keeping a watch on.

Okay. And let me move to Egypt. Would you please discuss the exploration well in the field in the Eastern Desert and that success and what the implications are for that new knowledge?

Yes. It's Thor here. Yes, we drilled into that zone, and we were a bit surprised, I guess, at the volumes that came in with that well. And I guess what's even more surprising is that the rates have sustained themselves quite high. So currently, what we're doing there is we're looking back at the seismic and doing technical work on it to see if there's additional opportunities to grow further wells in the next while on that.

The next question is a follow-up from Stephane Foucaud with Auctus Advisors.

So following up on the question from Charlie about Gabon. Where would you see production setting at once the program is finished early [indiscernible] in term of production plateau at that point? And then I have a question about interest.

Okay. I mean on a -- I mean, as you know, we're drilling some kind of being a bit speculating a successful case basis, we're currently somewhere in the region between 14,000 to 16,000 barrels a day gross. I would expect to be somewhere between 20,000 to 23,000 barrels a day on completion of the program.

It really is dependent on 2 things. One is within that program, we are currently considering to drill a gas well. And that gas well will enhance the gas availability for gas lift and gas injection and field fuel in in the Etame field. And currently, the more gas we can deliver into the existing production wells, the higher we can cycle the compressors, and therefore, we will have enhanced oil recovery from existing production which is completely separate from the new wells we're going to drill.

The second part of that is when we go to drill the 5H well in Ebouri, we are going back into that structure that we really haven't looked at for over 10 years. We've got some estimates as what we consider this well may be able to perform. But the upside of those estimates, the range is clearly large. So depending on what we encounter in that far reach well in 5H, it could have a meaningful change in the production. But rule of thumb, I would expect to be between 20,000 and 23,000 a day gross out of Gabon at the end of the program.

I guess one thing that we're pretty happy with is that on the Ebouri field specifically, the continued performance of the 2H well as well as the 4H well, which I think you're probably aware of, we brought on a year ago under a test program, that well is still flowing at a pretty good rate. So we're pretty happy with what we're seeing out of Ebouri right now, and we expect that next well to be good as well.

And a quick one for Ron. The -- in the CapEx includes capitalized interest, $20 million or so. So I assume this is not cash. This is something that -- it's an accounting CapEx, for a lack of better words, correct?

It is. And you'll see on Slide 11, how we split out the CapEx by country, and we've got the sort of wedge in relation to capitalized interest. I may have to correct you. I mean, it is cash. It's whether you pay the bank or whether you're paying for the CapEx, but the cash does lead the bank in [indiscernible].

The next question is from [ Aaron Schafer ] with [ Kornitzer Capital ].

What prices did you realize during the quarter for your oil? And then as my follow-up, what prices are you realizing thus far this year?

Okay. We're just getting that schedule. I mean, the -- again, if you look into the earnings release, Aaron, on Page 5, we give a breakdown of the 3 months through 31st of December. And you can see the realized prices that we got for our crude right across our asset basis there. So Gabon, it was about $58. Egypt, $54, and Canada, $53. So again, it was quite -- it was obviously a suppressed market as we went through the end of 2025. You should see obviously that coming up in Q1 2026.

This concludes the question-and-answer session. I would like to turn the conference back over to George Maxwell for any closing remarks.

Thank you very much, operator. I'd like to thank everyone for joining us today in our -- our 10-K -- 2025 earnings call. I think when we entered 2025, there was a lot of speculation about the size of projects that we were undertaking and the size of CapEx spend we had in 2025. And I guess a lot of risk factors added on to our ability to execute and deliver through 2025 on these major projects while still maintaining the returns to shareholders through dividends and keeping a very prudent position around our balance sheet. And I think when you look at the results for 2025, it's very clear we've achieved exactly what we said we were going to do when we had this call -- a similar call 12 months ago.

Now we're now in a position where when we look at the project in Cote d'Ivoire, that's significantly derisked with the vessel on its way back and production lined up to begin again in Q2. So when we look at the CapEx year for 2026, we don't have a significant development CapEx, i.e., a major project of construction. What we do have are major CapEx investments in drilling activity to add liquid production to our production facilities, and therefore, cash -- significant cash generative opportunities.

Given where we are on these projects, although we have a significant CapEx spend planned for 2026, that is money going into the ground to come back out in cash in the near term. And that's a significant difference to the type of project we were executing in 2025, which were development capital projects for construction of production facilities. So I think we've demonstrated the success of our ability to manage and work with our partners to achieve the successes that you see in 2025. I think we should hope the market should have some confidence in our ability when we go through the drilling activities, both in Gabon and with our partners in Egypt and in Cote d'Ivoire that we will be successfully executing those in 2026.

So with that, I'd like to thank everyone. I think we've had a very successful 2025. The diversification and derisking of the company's cash flows and production opportunities are starting to pay dividends for us, and we'll continue to see that grow through '26 and into '27. Thank you very much.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Thank you for joining us today for a fireside chat with chief Executive Officer, George Maxwell from VAALCO Energy. I am Jeff Robertson, Managing Director for Natural Resources at Water Tower Research. Before we begin, I would like to remind participants that our discussion today could include forward-looking statements as of today, December 2, 2025. VAALCO's disclosures regarding such statements can be found on the Investor Relations tab of its corporate homepage.

VAALCO is an international oil and gas exploration company with assets located in Gabon, Egypt, Canada, The Ivory Coast, and Equatorial Guinea. VAALCO's asset portfolio combines a mix of short-cycle development projects and long-cycle development projects and exploration prospects that expose the company to future growth opportunities and support management's goal of building value and returning cash to shareholders.

With that bit of introduction out of the way, George, thank you for taking the time to join us today.

Thank you, Jeff. Thanks for the introduction, and I'm looking forward to the chat.

Before we get to the development or the drilling campaign that's getting underway in Gabon and some of the plans for Côte d'Ivoire for 2026, I just want to revisit some of the capital program for 2025. VAALCO's original CapEx outlook for the year, which was published back in March called for total CapEx in the range of $270 million to $330 million. The midpoint of total NRI production was estimated to be about 15,600 BOE per day.

The latest full year estimates, which were updated on November 10 in conjunction with 3 quarter earnings payment to the CapEx midpoint at $243 million or 20% below the original midpoint impact NRI production midpoint at 16,500 BOE per day or a 6% increase from the original midpoint. George, can you walk us through where the CapEx savings have come from? And really what's driven the better than originally expected NRI production outlook?

Yes, I can. I mean we indicated some of these responses in our last earnings call. And predominantly, we've seen with a softening commodity price, we revisited our CapEx program for 2025, and we've removed around about $20 million of discretionary CapEx that was originally planned for this year. In addition, we've seen some increases in CapEx, primarily around the Ivory Coast project around the MV-10, where we pulled forward about $10 million of CapEx into 2025 to ensure that we can keep the MV-10 project on schedule.

What we've also seen against the original budget is a delay in the drilling rig for the rig -- the drilling program in Gabon. That's been delayed probably between 2 to 3.5 months due to the availability of the rig. So we've seen some of that slippage for the capital program for Gabon slip into 2026. So those are the 3 key elements that have allowed us to have a lower CapEx guidance for 2025. When we look at the production and the performance, particularly in Gabon, we've seen continued improvement from our forecast position and our modeling position from the Etame field.

Now part of the production increase has come from the continued flowing of 4H on Ebouri. We started that well up. It's been flowing very well for most of 2025. We started that well to allow us to test exactly how we were handling the H2S issues that we are all well aware of an Ebouri and whether those could be handled with the chemical scavenging that we have been planning for.

I'm happy to say that well has performed well. It's getting us above -- well above our production forecast. When I look at how much of this increase on the NRI performance is related to reservoir performance and how much is related to the topsides activities that we undertook in 2022 and 2023, there's probably about at least 1,000 barrels a day contributing to those combined factors. And about 60% of that comes from the reduction in back pressure that we successfully completed with the reconfiguration of the field and about 40% of that is coming from enhanced field performance.

With respect to the production performance, is it reasonable to expect that you may see some positive performance-related revisions when you go through the year-end 2025 reserve evaluation process?

There's 2 sides to that. One is definitely, yes, we are anticipating or we do expect to see significant revision movement within our reserves position. Now obviously, we can't quantify that yet until we go through the evaluation process with Netherland, Sewell. But given that we have not spun the drill bit in Gabon for 2 years and what we've seen in the production performance, the opportunity does give rise to significant revisions within the profile. So that's certainly what we are anticipating, but we won't be able to quantify that until we complete the exercise in early January.

I think the original plan in Egypt that you laid out earlier in the year called for 8 to 13 new wells through the end of September. VAALCO has completed, I think, 14 new wells in the year. Can you talk about what's driving some of the efficiency gains that you're seeing in Egypt that allows you to do more projects with the same or even hopefully a little bit less capital?

Yes. There's 2 key elements there. The first element is, obviously, we've had this drilling rig working continuously for probably close to [Technical Difficulty] now. And that position allows the efficiencies on how we're executing the wells and with the experienced team on board and the performance of the rig. So we've gained efficiencies there and those efficiencies continue to accumulate for us in each well we drill.

And secondly, we've established in Egypt from where we were when we first acquired that position back in 2022, we've continually improved the supply chain for providing the equipment inside Egypt for delivering these wells. So we've got limited to no downtime waiting equipment, limited to no downtime on rig performance. And that, combined with the types of wells we've started drilling now with more of the slant wells have contributed to us being able to drill more wells with the same level of CapEx. And you can see the -- although we're doing a little bit of a post-action review here, you can see how well it's held up in the Egyptian production performance.

I know you -- VAALCO won't provide any detailed capital spend or operating update for 2026 until probably March of next year when you report your year-end financial results. But from a high level, George, how does the result -- how do the results in Egypt make you think about constructing a capital program for that asset base in next year?

We definitely are reviewing that right now. The first key element here is to understand the after-action review of the wells that we've drilled in 2025 and the ones we are just finishing off here in Q4.

And then to review the performance of those wells and how they delivered and what have they delivered in respect of the reservoir performance that was anticipated. So before we move into a 2026 program, we have to do a review of where we can optimize the next drilling sequence in what is an aging asset. So where can we get the biggest bang for a buck and targeting both the workover positions and the new drill opportunities.

What are we doing when we look at the opportunity in South Ghazalat? We're trying to evaluate that now between the gas and oil split, and we've -- that's still under evaluation. So I think when we look at Egypt's performance, it's been a strong performance in 2025, and we're going to have to do an evaluation of the subsurface position of -- to exactly where we want to position any 2026 drilling program.

Turning to Gabon, you mentioned that the rig was a little bit late coming off its prior contract. Is the rig on site at Etame now? And can you talk about how that drilling program will unfold as we look into 2026?

Yes, I can. So the rig is on station. It arrived with us last week. It's -- we had a couple of days waiting on weather before we could pin it to the platform. But it is pinned to the platform now. And as of today, I think we're currently jacking up the rig. So we would expect to spud the first well in the next 72 to 96 hours. So that would be the first well in Etame.

When we look at the program, and as you know, we've got 5 firm wells and 5 optional wells. So we start the program in Etame with definite 2 firm wells to drill there with an option of a third that we may consider during this program. And then the rig would then move to SEENT where we plan to drill a gas well for field fuel to reduce our diesel consumption.

And then it would -- if we don't exercise options, we'll then move to Ebouri with the 2H workover -- sorry, the 4H workover and then a position on 5H drill. So it's quite an extensive program. We can be doing up to 10 wells. However, what we're trying to cycle in here is how the first wells are performing and trying to make a judgment call as to when we call off the options to minimize the amount of rig moves we have within the field.

So the current -- or maybe it's a little bit revised from what you talked about in prior quarters, creates a more efficient drilling program with the rig. Is that what you're trying to explain?

Yes. I mean before -- because we initially were focused on moving, I guess, to Ebouri as the first location. But because we've seen strong performance on 2H, strong performance on 4H, and that has necessitated that, perhaps we go for -- fill up the Etame slots first. In addition to that, over the last 6 or 7 months, we've seen a depletion of the gas well in SEENT, and we've seen an increasing consumption of diesel in order to power the field.

So that kind of brought forward that gas well in SEENT in order to alleviate the OpEx concerns that we have for increasing diesel. So it's just a basic resequencing. But what it does make us do is consider when we exercise options, the timing of those options to minimize the rig move because the options that exist, they exist in SEENT, they exist in Etame and they exist in Ebouri. So what we try to do is get our ducks in a row for exercising those if and when we want to minimize moving between the 3 main platforms in the field.

Can you put a range on the -- dollar range on the amount of OpEx savings that you might be able to achieve with the new gas well that you plan by displacing diesel as fuel?

It's probably somewhere between $350,000 and $500,000 a month.

You talked about Ebouri for the 4H well performing well to the crude sweetening chemical process that you all are testing in that well. How does the performance there impact the ability to monetize the reserves, which have been stranded since that field was partially curtailed back when the H2S concentrations increased?

Well, some of those reserves already came back when we put forward the plan in 2024, and we confirm the viability of that plan. So some of the reserves came back under the 2P scenario. Certainly, when we look at the issue on 4H and the performance of that well, given the age of the ESPs and the completions, that's certainly performing well.

And there may be a narrowing of the opportunity to work over that well because it's performing so well, and there may not be enough reserves left in that well to justify a full workover. When we then look at 2H, 2H has considerable reserves still to produce. And the workover in 2H is really to facilitate our ability to inject the chemicals downhole will be much more efficient in the scavenging operation for the H2S. The key, in my view, is the opportunity to the sidetrack on 5H which I think holds a great opportunity for enhancement of our position in Ebouri and really monetize. To answer your question, I think the bigger prize is on the 5H drill than the other 2 potential workovers.

At the Capital Markets Day in May of earlier this year, this -- I remind people the slide deck is available on VAALCO's website under the Investors tab. The Phase 3 development program in Gabon, which is beginning now was expected to test 2P reserve volumes in excess of 10 million BOEs and potential incremental initial production of about 16,000 BOE per day. Given the timing of the program and how you have it laid out now, George, should we expect those projects to be evaluated in time for later 2026 production and year-end '26 reserve bookings?

Almost definitely, I would say. I mean as I mentioned, the workovers, such as the workover in 2H doesn't really enhance any reserves. It's there to make it more efficient to produce with the scavenging opportunity on the downhole, the workover for downhole injection. But certainly, when we look at the Etame position and in particular, the Ebouri position, those are where the -- primarily the most of the reserves will come from.

There is an opportunity for an optional well on SEENT, which is a little bit more complex, a little bit more difficult to drill, a little bit further outreach from the platform. But when we look at the main contributing opportunities, they reside within Etame and within Ebouri. So we're looking at potentially the drilling phase completing depending on how many options we exercise somewhere towards the end of Q3 in '26. So that does give us enough time to ensure that the results of that are fully within our 2026 reserve process.

As I said earlier, the 2026 financial and CapEx guidance won't be released until March of next year. But with the 5 committed wells in the Gabon campaign, can you put a rough CapEx range around or an estimated range around those wells for us?

Yes. I mean it's -- we've had obviously slipped some of 2025 CapEx into 2026, and that value was somewhere around, I think I mentioned earlier, about $40 million of that in relation to the program slip. And we've -- on a gross spend basis, we were always budgeting around $250 million. So a net to VAALCO about $160 million on those wells, and we've quoted that previously in our Capital Markets Day.

So you can work out probably somewhere in the region net to us of about $100 million, $120 million may slip into 2026 for the CapEx program from the previously disclosed information. Now when we come to do our CapEx guidance, we'll also have a lot more granularity to that as it folds out to the totality of our investment program across all our activities. But that's a rough rule of thumb for Gabon for the drilling side.

Elsewhere in Gabon, a seismic program could commence on the Niosi and Guduma exploration licenses later in 2026. You talked about the performance of the reservoirs at Etame exceeding expectations. Should we expect that some of that outperformance at Etame and the upcoming development campaign to have an impact on the seismic interpretation and prospect development on those licenses? Or are they in some sort of a different petroleum system?

Well, they're all in a very similar petroleum system, but we're talking about connectivity of these systems. And I don't believe we've seen from the existing seismic within the Etame field block that level of connectivity. Now the seismic activity, yes, were due to commence in early -- late '25, early '26 for Niosi and Guduma, and what we do believe, and we've put this up on the map, and I think our partner, BWE believes also is that we have active hydrocarbon systems from Etame down south through Dussafu where BWE operate.

So this seismic program is key to identifying those active -- potentially active hydrocarbon systems and where potential connectivity can be made, not just -- as I said, I don't think we've got connectivity in the hydrocarbon systems, but the connections back to production facilities is also key. And that's where we see potential life extensions both in Dussafu and in Etame, where near-field opportunities to tie back to existing infrastructure is where we see the prize on the seismic. So on the seismic taking place, acquisition, then interpretation is going to be all through 2026 is what I understand.

If we shift gears to Côte d'Ivoire, the operator of the Baobab field expects the FPSO to return, I think, late in the first quarter of 2026. And I think you said on the call recently that the hookup should be completed during the second quarter. George, just from an operating perspective, how much time does it take -- generally take to restore the production to -- or restore production in the field to the levels that are approaching where it was when you took it offline?

Well, we've got -- in the program that we've seen to date from the operator, I think there's about a 70-day planned for the hookups. So that's picking up the flow lines and reconnection back to the FPSO. Also during that time, obviously, we've got systems commissioning, et cetera, will all run parallel to that. And that's really that 70-day period is where we see between the arrival of the FPSO coming into the field which is going to be sometime during March from a January 31 sailaway and the recommencement of production sometime during May.

So those time lines are currently still within the project plan, and we're not seeing any movement on that. As we mentioned earlier, we're still seeing sailaway date for 31st of January, which is a key date where all the work on the vessel has been completed and the contracts laid for the recommissioning.

So it's -- right now, what we still haven't seen yet is the complete start-up sequence for the wells, and that will really then dictate what levels of production will come on when. We've got some forecast for that. But until we see the full start-up sequence, it's difficult to comment on that. That's something we'll definitely be giving guidance to during Q1 when we give our 2026 guidance.

Do you expect the FPSO upgrades to have an impact on operating costs and operating efficiency kind of like what you have -- what you saw when you reworked the infrastructure at the Etame field?

There's a couple of points there. One, this is slightly different from what we did in the Etame field. In the Etame field, we moved a lot of the processing equipment onto the platform. And therefore, we've just got a dump storage vessel, and we moved and modernized all the processing equipment through Etame.

Here, what we're doing is -- or what the operator is doing is effectively reconditioning the existing processing plant. So we're not seeing significant upgrades in the processing plant from that standpoint. But we are seeing, obviously, renewals, renewals of steel, confirmation through the tank, the recoating of the tanks. We're seeing the class issue being renewed for the vessel through its tenure to end of field life or beyond.

So we would expect to see some efficiencies through reduced downtime for maintenance. We've also got added engineering capacity on for some of the -- to accommodate Phase 5 drilling and to accommodate full lines for Kossipo. So there are efficiencies in there that will come with volume when the Phase 5 comes in on a per barrel basis. But dollar-for-dollar reduction, I think best way we'll see that is once it's back on stream and see where we are for maintenance downtime. That's a key that we'll be focused on.

You mentioned Phase 5 development. So the development program in Baobab is expected to begin after the FPSO is put back in service. You talked about some of the upgrades. Do -- should you expect those to shorten the cycle time of connecting wells or new wells into production?

There's not a shortening of the cycle time. I mean the upgrades that have been done to the FPSO in order to accommodate Phase 5 on Kossipo facilitates that connection. So it means there's less -- there's not a requirement for engineering work that would have been required if we hadn't taken the vessel offline. So it's not -- I don't see any shortening of the connection time or the hookup time. It's just that now we have a topside position that can accommodate those additional production lines.

Again, at Capital Markets Day, the Phase 5 development plan as it -- or program as it was laid out at that time, talked about targeting gross reserves of about 33 million BOEs with a peak gross production of about 27,000 BOE a day. How should we think about the reserve and production impact of Phase 5 in 2026? Or would that be more of a 2027 impact?

Yes. Right now, we see probably a late Q3 spud date for Phase 5. So that's definitely going to fall into 2027. I don't see us -- and again, we haven't had detailed discussions with the operator, but I don't see us getting enough wells down to make any significant reserve impact in 2026.

You mentioned the Kossipo development project as a potential subsea tieback to the FPSO. Can you share any color on the timing of that project and what it could mean?

Yes, we still have time for those discussions with the operator. I think when we put that in our capital markets plan, we had it somewhere around late '27 into 2028 for that. But if you just think of that potential time line for the establishment of well locations and then equipment ordering for subsea trees, we're probably into the 2028 cycle time by the time we've got that ready fully planned, we've got an FDP planned and submitted to the government. And then we start to look for rig and equipment. So it's probably going to be a 2028 start-up position at the earliest.

George, if we move to Equatorial Guinea, you talked recently about continuing to evaluate alternatives to develop the Venus discovery in the most economic fashion on Block P. You mentioned that a subsea tieback to a facility located in shallow water on the shelf could become the preferred scenario. Can you talk about how that type of a development, number one, impacts the decision line toward an FID and ultimately timing of when that could begin producing?

Yes. So the original plan of development was a MOPU on the shelf with a long reach drill from the shelf through down into the reservoir. And what we tried to do in the FEED study was look at how can we switch CapEx for OpEx in a field that has a relatively short life of about 60 months. It's high production short life. And when we did the FEED study, part of that was to look at can we look at leasing a MOPU and planting it on the shelf and how do the economics work?

And going through all of that position, we did get to a point where the proof-of-concept was definitely there. We'd already established that. The proof-of-concept and the long reach drilling was there. But what it also highlighted was drilling extended reach and the angles of attack coming into the reservoir on a 3- to 4-kilometer basis. We're giving some high-risk factors, and it was possible, but it was a high-risk factor.

So what we jumped to was how does that look if we did a vertical drill. And all of a sudden, all the risk factors on a vertical drill given how shallow the reservoir is from the seabed disappear. And it takes -- it gives us the opportunity to have much more accurate well placing especially for the water injector, which gives us a greater confidence in the sleep efficiency for the reservoir.

And therefore, when we did remodel the reservoir simulation model, we came back and reconfirmed the potential of this field to produce 20,000 barrels a day. So taking that derisked position from a vertical drilling solution into account, we then said, okay, in order to be able to do that, we need to look at the efficiency of how do we do subsea tieback to topsides. And that's really where we've extended the FEED to look at the opportunity set where another FPSO coming in and that tieback opportunity for location of trees and timing, et cetera, how does that stack up against the surface MOPU that we would have on the shelf.

And that's where we've kind of extended the study to, and we've looked at those opportunities. And when we look at the economics, now, of course, a vertical drill from a drillship on a day rate basis is much higher than a jack-up on the shelf. However, the time is about -- is less than 1/3 to drill those wells from vertical than it is to drill from the MOPU. So from a drilling perspective, it's almost a wash. And so therefore, we're looking at how efficient can we get on the top side.

So that's really what's moved it from that extent to a simple MOPU and storage at the shelf. And it really was to try and derisk the 2 elements, the key elements for this study that came to -- came out of the study for me was, again, how resilient the reservoir will be if we get the water injection well in the right placing and the kind of benefits we can get from that in the order of the recovery factors. But certainly, it took away 90% of the risk factors and complexity on the drilling position, mainly because we can come into the reservoir from a much more efficient standpoint from the vertical versus the shelf drilling.

Do you expect to be in a position with all the evaluation to consider an FID at some point in 2026 on that project?

I would certainly hope so. We -- I mean this project, we've demonstrated already, it has considerable value to the company, both in terms of production and economics. And it's just about balancing our capital spend with the commitments we have right now and making sure that if we were to enhance that capital spend, we're very firm on the execution plan in Equatorial Guinea to give us that return as quickly as possible.

So there is a little bit of planning has to take place, so we don't overstress our capital position in the near term, but also make sure that we exploit as early as possible the value opportunities that can give us great returns to the company and to our shareholders.

As I said at the outset, VAALCO has a project portfolio across multiple countries in Africa that expose it to significant reserve and production growth over the next -- over the coming years. Upcoming activity in both Gabon and Côte d'Ivoire could begin to crystallize some of that opportunity over the course of 2026 and 2027.

George, just to wrap up on your -- the capital framework, can you talk about how you think about managing the program, which is essentially a multiyear-type program and opportunity set against the backdrop of $60 plus or so Brent oil as we look into -- at least today as we look into 2026 and how that impacts VAALCO's ability to maximize returns and continue your goals of returning cash to shareholders?

Yes. I mean clearly, we've got to focus on whenever we invest in the dollar, how quickly does that dollar come back to the company. So greenfield developments take some time and greenfield developments -- making the commitments on greenfield developments can tie up cash for extended periods of time. In order to commit to the greenfield developments such as EG or CI-705 that we're involved in as well, then we need to make sure that the near-term production and the operating cash flows coming from those near-term productions are coming back as quickly as possible.

And that's where -- what we're investing in Gabon right now, enhancing that production and working closely with our partners there to ensure that we not just provide enhanced production, but we provide further longevity to that field. And it's worth remembering for Etame that when the company first entered that in 2002, it anticipated 5 million barrels to be recovered. We are currently not far off of 150 million barrels of production. So this is definitely an asset we want to invest in.

It's definitely an asset we think we can continue with its longevity. We then couple that with the near-term production opportunities in CDI and where we are with the investments that we're making with our partners there and the investment in, again, enhancing the longevity of CI-40 right through to 2038 with the refurbishment of the FPSO and the commitment to at least Phase 5 and drilling programs to again enhance that recovery.

Those are the -- for me, the cornerstones of where our investment profiles will be because those are the shortest time frame for those dollars to come back. Now when those dollars come back, we then have the choice. What do we do with those dollars? Do we go after our greenfield opportunities and also provide a return to our shareholders. And this is where we have the balance. We have a portfolio. That portfolio is there to ensure near-term monetization, but longer-term operations through into the 2040s.

So the company has a visibility way beyond the next 2 to 3 years. And it's balancing those activities because we have to continue to invest. We can't just manage depletion because that is -- especially at lower oil prices, that's ever increasing circles. There's only one way that's going to happen and operating cash flow goes down. So we have to invest in order to enhance the production and manage our cash flows at these low commodity prices.

And I think where we are right now, we've got lots of opportunities. I would love to have an endless source of liquidity to go after them all today, both human resources and monetary, but we can't. So we have to balance that with recognizing where the near-term opportunities deliver the near-term returns to both the company and the shareholders.

Well, I think, we'll leave it there for today. I know with the portfolio you have, we'll have plenty of opportunities to host another fireside chat as some of the -- as we get closer to the start-up of production in CI and progress on the development campaign in Gabon. So I want to thank you for taking the time for joining us today.

Thanks, Jeff, I look forward to it. And certainly, as we know, we started the drilling program. So by March, we're going to have an awful lot to talk about between Gabon and CI-40.

Good. For our participants, I want to thank you for joining us for today's fireside chat with George Maxwell from VAALCO Energy. Our research can be accessed from our website, www.watertowerresearch.com. The views expressed in this fireside chat may not necessarily reflect the views of Water Tower Research LLC and are provided for informational purposes only.

This fireside chat may not be redistributed or reproduced without the written consent of Water Tower Research and should not be considered a research or recommendation. WTR is an Investor Relations firm and not a licensed broker, broker-dealer, market maker, investment bank, underwriter or investment adviser. Additional disclaimers can be found at watertowerresearch.com. George, once again, thank you for joining us today.

Thank you very much, Jeff. Look forward to talking to you soon.

Thanks.

Bye-bye.

Good morning, everyone, and welcome to the VAALCO Energy's Third Quarter 2025 Conference Call. [Operator Instructions] Please also note today's event is being recorded. At this time, I'd like to turn the floor over to Al Petrie, Investor Relations Coordinator. Sir, please go ahead.

Thank you, operator. Welcome to VAALCO Energy's Third Quarter 2025 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the third quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions.

[Operator Instructions] I'd like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparison and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements.

Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and in the reports we file with the SEC, including our Form 10-K. Please note that this call is being recorded.

Let me turn the call over to George.

Thank you, Al. Good morning, everyone, and welcome to our third quarter 2025 earnings conference call. For over two years, every quarterly earnings call, we have met or exceeded our production guidance, consistently leading to strong operational and financial results.

The third quarter was no different with NRI production of 15,405 BOE per day, which was at the high end of guidance; working interest production of 19,887 BOE was above the midpoint of guidance, and NRI sales of 12,831 BOE per day, which was also at the high end of guidance. Our production and sales performance through the first 9 months of 2025 has been so strong that we have raised the midpoint of our full year production and sales guidance by about 5%, while also further reducing our capital guidance by almost 20% and maintaining our operating expenses virtually flat.

Ron will go into more detail about our guidance later in this call, but we believe that maintaining operational excellence and consistent production across our portfolio is essential to continued strong adjusted EBITDAX generation, which will assist us in funding organic growth initiatives while positioning us as a larger player in the industry. In the first 9 months of 2025, we have delivered net income of $17.2 million or [ $0.0016 ] per share and adjusted EBITDAX of $130.5 million.

It is important to remember that 2025 is a transitional year, and everything remains on track with our forecast. Production came offline in Q1 at Cote d'Ivoire due to the FPSO project, and we do not expect to start the drilling campaign in Gabon until late Q4 as we await the drilling rig's completion of its current commitments. This means that the meaningful production uplift we are projecting for these major projects won't begin until 2026 and into 2027.

I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire. In line with the project timeline, the FPSO ceased hydrocarbon operations are scheduled on January 31, 2025, with the final lifting of crude oil from the vessel occurring in early February. The vessel departed from the field in late March and arrived at the shipyard in Dubai ahead of schedule in mid-May 2025.

The FPSO refurbishment is well underway in the shipyard. Significant development drilling is expected to begin in 2026 after the FPSO returns to service with potential meaningful additions to production from the main Baobab field. We now have a 10-year extension of the license on CI-40, extending it to 2038.

In March 2025, we announced a farm-in agreement for the CI-705 block offshore Cote d'Ivoire where we will operate with a 70% working interest and a 100% paying interest. In Q2, we received seismic data for the block, and we are conducting a detailed integrated geological analysis to assess and mature our understanding of the block's overall prospectivity as well as the basin's overall potential.

We believe the block is favorably located in a proven hydrocarbon system and is approximately 70 kilometers to the west of our CI-40 block. We have demonstrated our ability to acquire, develop and enhance value through accretive acquisitions, and we are excited about the prospects in Cote d'Ivoire.

Moving to Gabon; given that we haven't drilled a well in Gabon in over two years, we are very pleased with the positive overall production results, including strong production uptime and improved decline curves on the wells in 2025. In July, we successfully completed a planned full field maintenance shutdown of the Gabon platforms to perform safety inspections and necessary maintenance. This is the first time we have had to perform a full field shutdown in Gabon since the FSO was brought online in 2022.

This has helped to contribute to the strong uptime numbers in Gabon that we have had over the past several years, which can be seen in our supplemental presentation. While we secured a drilling rig in December 2024 for our 2025-2026 drilling campaign, the timing of when we start the drilling program has always been dependent on the rig's completion of its existing commitments. The rig is now being released and moving to Gabon.

As we discussed in the Capital Markets Day, we have some very strong drilling opportunities and the additional data gathered during the upcoming drilling program will help us high grade and derisk additional well locations that have already been identified. We plan to begin the drilling program on the Etame field platform, and we are currently planning on moving to the Ebouri wells later in the program because of the current robust production profile of these wells.

In particular, we remain very pleased with the extended flow test on Ebouri 4H well, which is continuing to surpass our initial expectations. We originally wanted to gather information on the H2S concentrations at this location to aid in equipment design and to evaluate our chemical crude sweetening process. The 4H well has now flowed for all of 2025 at a gross average of around 1,000 barrels of oil per day with the H2S concentration within our modeling expectations, demonstrating our ability to chemically treat the oil.

The wells production has helped Gabon exceed its production guidance in 2025 while adding some additional production costs for chemicals. Regarding our exploration blocks in Gabon, the Niosi Marin and the Guduma Marin, we are working in conjunction with our partners and the operator, BW Energy, on plans for the two blocks moving forward. A seismic survey to fulfill a work commitment on Niosi is being planned for acquisition in late 2025 or early 2026.

Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks. Turning to Egypt; in the fourth quarter of 2024, we contracted a rig and drilled two wells starting a drilling campaign that has carried into the first 9 months of 2025. We have drilled and completed multiple wells in the first 9 months of 2025 and are continuing activity into the fourth quarter.

We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. We've been able to drill more wells faster and cheaper than what we had in the budget and for the same amount of capital, which has also positively impacted the production. We also continue to workover and recomplete wells in Egypt.

Both the drilling program and the workover program in Egypt add solid production and are economic even in lower commodity price environments. We are continuing to evaluate the exploration results in South Ghazalat, where the wells are encountering both oil and gas net pay zones with different levels of reservoir pressure. We are incorporating well results and updating our understanding of the area with new mapping that will determine potential additional prospectivity for the area.

In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. This summer, we began our Front End Engineering Design or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risk and challenges from the shelf location.

We have expanded this review to explore more efficient development opportunities through a subsea development, which would also significantly simplify the drilling operations and well design, and this is currently underway. We are very excited to proceed with our plans to develop, operate and begin producing from the discovery on Block P offshore Equatorial Guinea in the next few years.

Turning to Canada; we successfully drilled and completed four wells in 2024. We also drilled a well in the Southern Acreage in late 2024 that could help us better understand the acreage and upside in that area. While we remain optimistic about the drillable inventory in Canada, we decided to postpone our Canadian drilling program in 2025 due to the current commodity price environment.

We will continue to monitor the performance of our wells and plan for future drilling opportunities. Before I turn the call over to Ron, I would like to thank our hard-working team who continue to operate and execute our strategic vision and help us deliver these outstanding results. We are well-positioned to execute the projects in our enhanced portfolio and our proven track record of success in these past few years should instill confidence for our future.

With that, I'd like to turn the call over to Ron to share our financial results.

Thank you, George. And once again, good morning. I will provide some insight into the drivers for our financial results with a focus on the key points. Let me begin by echoing George's comments about our continued success through the first 9 months of 2025, driven by our strong operational performance.

We have met or exceeded production guidance for the past 2-plus years, driven by strong production in Gabon and Egypt despite Cote d'Ivoire being offline since January -- since late January. This performance has allowed us to positively adjust the midpoint of our full year production and sales guidance. In the supplemental deck on our website, you can see that NRI production is up 900 BOE per day and sales are up 750 BOE per day.

You will also see that our full year capital midpoint guidance is down almost $60 million to around $240 million in total. Finally, we have worked hard to keep our absolute production expense in line with our original guidance. But with the increase to sales and production, our production expense on a per BOE basis is down about $1 per BOE.

Our overall results and ability to manage multiple assets and high profile capital projects across multiple countries are reflected in our updated 2025 guidance. For Q4 2025, we are forecasting production to be between 20,300 and 22,200 working interest BOE per day and between 15,600 and 70,300 NRI BOE per day.

This is up compared to the third quarter due to the planned maintenance turnaround that occurred in Gabon in July and continued strong production in Egypt. For the fourth quarter, we are forecasting our sales will also be higher compared to Q3 due to more offshore listings in Gabon. We also expect our absolute operating costs to be higher compared to Q3 due to the additional sales, but virtually flat on a per barrel of oil equivalent basis.

Finally, looking at CapEx, our Q4 spend is expected to be higher than the third quarter as we begin the drilling campaign in Gabon. We are forecasting between $90 million and $110 million, and we anticipate continued spending in CDI and Egypt in Q4 more or less in line with Q3. In the third quarter, we generated $1.1 million in net income or $0.01 per share and $23.7 million in adjusted EBITDAX.

Our NRI sales for the quarter were at the high end of guidance at 12,831 BOE per day. Both sales and pricing moved against us in the third quarter, with sales down 33% due to the fewer listings in Gabon, driven by the planned turnaround and pricing was lower by about 7% quarter-on-quarter. We have seen higher volatility in the commodity price environment thus far in 2025. Our hedging program has always looked to help mitigate risk and protect our cash commitments.

But with the RBL now in place, we are moving towards a more programmatic hedging program that will be more consistent over a rolling time horizon. With this in mind, we took advantage of periods of higher oil prices during the third quarter to add more hedges for the 2026 hedging program.

The company now has about 500,000 barrels of remaining 2025 oil production hedged with an average floor of approximately $61 per barrel and about 800,000 barrels of oil production hedged for the first half of 2026 with an average floor of approximately $62 per barrel. We are targeting around 40% of Half 1 2026 oil production to be hedged by year-end. Our full hedge positions are disclosed in the earnings release.

Turning to costs; our production costs for the third quarter of 2025 were at the low end of guidance on an absolute basis and on a per barrel basis. Absolute expense was $29.87 million, a 26% reduction quarter-over-quarter and on a per barrel basis was $25.24. G&A costs were in line with guidance and remained relatively flat quarter-over-quarter. Our focus remains on keeping our costs low to enable us to maximize margins and increase our cash flow.

Moving to taxes; we reported an income tax benefit of $3.6 million for Q3 2025, which was comprised of an $8.6 million current tax expense, offset by a deferred tax benefit [Technical Difficulty] Gabon's allocation of profit oil between the time it was produced and the time it was taken in kind. Turning now to the balance sheet and cash flow statement. Unrestricted cash at the end of the third quarter was $24 million.

Collections from the Egyptian General Petroleum Corporation, EGPC, since the 1st of January 2025 totaled over $103.6 million, and the company expects to receive further material payments against its arrears before year-end. We anticipate that our annual receivables balance will be half of what it was in 2024 by year-end. Monthly invoices are now paid in full and regular repayments are being made against the receivables balance.

As we discussed last quarter, we added a reserves-based credit facility with an initial commitment of $190 million and the ability to grow to $300 million. Shortly after the third quarter, we successfully completed our semiannual redetermination with lenders and reaffirmed the initial commitments.

As of September 30, 2025, VAALCO had $60 million outstanding borrowings, which is the same amount outstanding as we had at the end of the second quarter. In Q3, we spent $48.3 million in cash CapEx, well below our third quarter guidance of $70 million to $90 million. Additionally, we returned $6.7 million through dividends to our shareholders.

We believe that our current dividend yield of around 7% is very attractive, especially considering the meaningful upside potential in production and reserve growth that we outlined in the Capital Markets Day over the next few years. In closing, we're continuing to see strong results. We are well-positioned to execute and fund a robust organic capital program that should help to increase production and reserves for 2026 and beyond.

With that, I'll now turn the call back over to George.

Thanks, Ron. We will continue to execute a strategy focused on operating efficiency, investing prudently, maximizing our asset base and looking for accretive opportunities. As you have heard this morning, we continue to meet or exceed both our quarterly guidance and analyst estimates in the first 9 months of 2025 as we have done for the past several years.

This has allowed us to increase our full year production guidance by about 5% while lowering our full year capital guidance by about 20%. By delivering on our commitments to the market, I believe we have earned the credibility with our shareholders, and we will continue to deliver on the exciting slate of projects that we have over the next few years. Our entire organization is actively working to deliver sustainable growth and strong results.

We have multiple major projects underway that are anticipated to meaningfully grow production and reserves. Through the first 9 months of 2025, we have generated $130.5 million in adjusted EBITDAX, and this is with Cote d'Ivoire offline for the FPS again. Through the first 9 months of 2025, we have generated $130.5 million in adjusted EBITDAX, and this is with the Cote d'Ivoire offline for the FPSO project and no new wells drilled in Gabon.

In addition to funding our capital program, we have remained focused on returning value to our shareholders. In the first 9 months of 2025, we returned around $20 million to our shareholders through dividends. With the Q4 dividend announcement, we will deliver another [ $0.0025 ] per share annual dividend for 2025, which at our current share price is a dividend yield of about 7%.

We are confident in our ability to execute on the many projects ahead, largely because we have been highly successful over the past several years developing and growing our assets. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserves and cash flow has led to outstanding results and has positioned us to continue to profitably grow in the future. Thank you.

And with that, operator, we're ready to take questions.

[Operator Instructions] Our first question today comes from Stephane Foucaud from Auctus Advisors.

So two questions. The first one is around CapEx. So reduction of CapEx in 2025. I was wondering what would be broadly the CapEx mix across the asset in 2025? And what it means the CapEx reduction in 2025 for 2026?

In other words, how would 2026 CapEx compare broadly to 2025? So that's my first question. The second question is about South Ghazalat. In your view, in a success case, how big could be South Ghazalat or what this result means in terms of -- compared to the existing reserve in Egypt?

Hi Stephane, I think -- it's Ron here. I'll take the first one on CapEx and CapEx guidance. So if you look at it between the midpoint of guidance, I think we moved about $60 million. $20 million of that is gone. That was discretionary CapEx that we took out in 2025. We've had about a $10 million increase in CDI CapEx, really just keeping that MV-10 on schedule. And that's very good news as far as we're concerned that everything is going well in relation to that project.

And the rest is really a shift in Gabon from the drilling campaign due to the delay in getting the rig moving out from 2025 into 2026. What I would say, though, is on Egypt, effectively, the Egyptian CapEx is the same number as we originally guided to, but we'll have completed 8 additional wells in that time period for the same CapEx. So again, that's a very positive efficiency that the guys have brought to the table in 2025.

And on South Ghazalat, one of the additional wells, as you know, Stephane, was out there, and I tried to touch on it in my comments earlier. So what we've seen there in the well that we drilled, we entered the gas prone zone with lower pressures, which indicates that there's potentially some gas depletion there. And we also entered an oil proven zone that had no pressure.

So what we're trying to establish now is the total extent of the oil zone, what that aerial extent could be and how large that could be for potential development and then understanding the reduced pressures around the gas zone and where that depletion may be. So having got the results of the well, we're going back to do our after-action review and establish where else within the existing structure that we understand, we'd want to drill additional wells there.

There are a couple of things outstanding in South Ghazalat. Whilst we had some commitment wells that we've already completed to keep the acreage. But in addition to that, we've also got some commercial issues around the PSC that we have to discuss before we get anywhere close to some kind of preliminary field development plan.

So there's more technical work to do, but there's also some more commercial work to do. We've always been hopeful that because it's such a prolific area out there in the Western Desert that this block will yield some interesting opportunities for us, but that's still to be developed and it's still to be evaluated at this time.

Our next question comes from Jeff Robertson from Water Tower Research.

Ron, just to clarify on the CapEx, did I hear you right that about $20 million of the reduced guidance is permanent reduction, in other words, getting -- either doing things at lower cost than budgeted or getting more done with the same amount of dollars?

That's exactly right, Jeff. As you know, we took Canadian drilling CapEx out very early, I think, in Q2 guidance, we pulled that out. That was about half of that. The other half is just discretionary CapEx that we pulled out over the last 3 or 4 months.

Are the efficiency gains that have helped in Egypt, are those sticky? In other words, does that -- you would retain those types of efficiencies if you look at a CapEx program in Egypt in 2026?

Yeah. I mean what we've got, Jeff, as you know, we've reduced that spud to basically take an online cycle time quite considerably over the last three years. We continue to drill and complete and bring online those wells at a much lower level of days versus what our initial expectations were. So those efficiencies are real. They're there. And if they continue into 2026, we'll continue to see less [ AFE ] costs for drilling in Egypt.

Okay. And on the RBL Ron, I believe the electric commitments is going to go up to $240 million in January. Is that a reflection of asset performance?

I think it's more a reflection of the current market, Jeff. I mean liquidity is going to be key for all upstream companies as we move into 2026, with softening commodity prices. And from our point of view, we have the availability there. I'd rather lock it in when we've been a position of strength than when in a position of need.

Our next question comes from Christopher Wheaton from Stifel.

Two, maybe three questions, if I may. Firstly, on Gabon production. You've not -- as you said, George, you've not drilled any wells for two years now on Gabon. And as you said, the Gabon drilling program shifted later in this year, you still delivered a pretty good production performance, and that's on uptime, if anything, slightly lower than it was last year.

I'm interested, is there the geology better? Are there particular wells performing better than you expected? I'm interested in what's been driving that production uptime. And then second question on really about 2026 CapEx and your ability to flex that as you've got more of the Gabon drilling campaign falling into '26.

You've got Cote d'Ivoire CapEx, obviously, as a given for '26 as well. I'm interested just what your key priorities for setting that 2026 capital budget are going to be given you've got a lot of things that you're kind of on the must do or have to do list. And therefore, realistically, are we going to see -- is there much CapEx flex below, say, 2025 levels that we might see for 2026 CapEx guidance? I'll stop there.

Okay. Let me start on Gabon. I mean, obviously, in the last -- ever since we've completed the reconfiguration, what's resulted from that is, I think as we've maybe discussed before, is a significant reduction in back pressure into the reservoir, which has enhanced not just well performance, but a lot of the field performance as well. We've also been working on the brewery side to continue the production in 2-H and then we've also brought on 4H.

We did that deliberately to test the levels of H2S that could be managed through the [ scavenger ] program. And we've continued to see 4H produced throughout 2025 with H2S levels well within our manageable range. That's been very encouraging, and it's also will lead when we get to the drilling program leads us to not just the 2H workover potential, but then 5H to go back and redrill 5H both -- goes across a fault block to enhance the production in the buoy.

So these results are -- and these test wells that we bring back on stream are really important for our understanding of how we're going to deal with the potential H2S as it comes towards us in the future. The -- you are correct in that when we look at the production profiles for the Etame field, we can see that we're producing well above the 1P decline curve and in some cases, into the 2P position.

We look at that and the questions are naturally come is the size of the tank larger -- our recovery factors are going up to the 50 percentile and higher. So there's clearly some geological remapping work that's currently underway that's required to understand this field better. I keep going back to some of the decisions way back in the early 2000s when this field had a life expectancy of 5 years.

And here we are 20-plus years later having produced close to 150 million barrels from the field, and it continues to give. So hopefully, the studies we've got in place over the next 6 months will start to clearly give a better definition around the geology and whether there is connectivity into the Gamba from the Dentale that's supplementing those production levels. With regard to the CapEx position of 2026.

Now obviously, as Ron mentioned, the delay in the rig coming to us for 2025 has delayed our program for Gabon. We continue with the position in Gabon with a 5 firm and 5 options. So there is some flexibility in the drilling program in Gabon. But as I've mentioned before, we've been studying these drill locations now for a few years, and we've got some pretty strong targets that we want to go after.

So that will give some meaningful production uplifts in Gabon. So whilst there may be not as much flexibility as we may want in the Gabon drilling campaign, that comes with the added benefit of significant additional production. With regard to Cote d'Ivoire, as Ron mentioned, we have spent a little bit more CapEx in '25 to ensure that the sail away date of the end of March for the FPSO can be met, and we've discussed that in detail with the operator.

There is a drilling program, as you're aware, to start the second half of 2026 in Cote d'Ivoire. The exact timing of that drilling program is still a little bit subject to, obviously, rig availability, equipment, et cetera. So there may be some flexibility there. However, again, these investments come with significant adds to production. So -- and as we know in Cote d'Ivoire, every dollar we spend is recoverable with $1.25 back in the cost oil. So whilst the CapEx may look slightly less flexible in '26 than it was in '25, it comes with considerable benefits.

Our next question comes from Charlie Sharp from Canaccord.

Can you hear me?

Yes, we can hear you.

Sorry about that. I was on a separate phone and here we are. So the question really is regarding timetabling of events next year. And I think you've just provided some useful information there on the planned sale away of the Baobab FPSO. I'm guessing from that, that you still expect to be back on stream there before the middle of the year in order to facilitate drilling sometime in the second half. That's one small question.

And then secondly, on Gabon, should we assume that you're drilling wells about one per quarter, in which case you'll probably be drilling into 2027? And will you be completing successful wells as you go or will you batch drill and batch complete?

Okay. So I'll start with -- you're correct in your assumption. We're still -- the sail away date is still for the end of January after the second dry dock period. The hookup is scheduled to be late March, early April and back on production by end of April, early May. So well ahead of the drilling program. And when we come into 2026, you'll see that coming into our guidance position, and we'll be able to give you much more detail at that time.

But that's the current schedule and everything on that project is currently on schedule. For Gabon, obviously, what we're trying to do here in Gabon, like I said, we spent a lot of time looking at these drill locations. Some of the -- as you may be aware, the imaging on the seismic here is not as clear as we would like it to be due to the interference of salt.

But that being said, we're planning to drill pilot holes in some of these locations to establish exact levels of hydrocarbons to then allow us to pull back and redrill or complete in a different zone. So when we look at the schedule right now where we're starting on the Etame field with two pilots, we would -- if both of those come in and remind the POSGs are 80% plus, we would drill and complete as we go. So we will not do that drilling. So we potentially have three wells on Etame if we choose to elect one of the options, one well on Seent and then a workover and well on Ebouri.

Our next question comes from Bill Dezellem from Tieton Capital Management.

Relative to the Cote d'Ivoire drilling program, you'd mentioned that that will begin in the second half of next year. Given that the FPSO will be back in the field and reconnected in May, what's the swing factor or swing factors that would drive the drilling earlier in the second half versus later in the second half?

Okay. So the biggest swing factor is exactly what we face in Gabon is the drilling unit arriving on time. When we look at where we are today, though, all the long lead items, the trees and the equipment, et cetera, are all ready to go. So it's all around the drilling unit and the timing of that. So when it comes off its existing contract, as you know, we may have a scheduled date, but if it's halfway through drilling a well for a previous client, then it has to complete that well before it comes to us. So it's really just the rig move would be the swing factor.

That's helpful. And then relative to Equatorial Guinea, you'd mentioned that you're looking at a subsea completion application. Was that part of the FEED study or are you now needing to do essentially a sidebar FEED study?

It's not quite a sidebar. What came out of the FEED study was what we were trying to achieve in the FEED study was how do we reduce the CapEx position that's in the POD. And what we were looking at was can we go to drill off the shelf with what we call a [ MOPU ], a self-elevating platform for production and basically put that to a leased unit rather than a capital unit.

What came from that is that there are -- given the complexities of the shelf drilling, getting the exact locations for the wells are possible but complicated when you're looking for the two producers and you're looking at getting a water injector in there with a long lateral to give you an efficient flow of production from the structure. So that sweep efficiency is very key to the recovery factors and the production profiles that we've estimated from Venus.

We've since and during the FEED completed a new static and dynamic model, which confirms the volumes that we announced back in the Capital Markets Day. But again, that dependency on the sweep efficiency from the water injector is critical to achieving these production levels. So when we looked at that risk factor, we said, okay, it's possible, but it contains risk.

And we then looked at a vertical solution and said, do we eliminate that risk factor significantly by coming from a drillship position vertically versus coming from the shelf. And the answer to that is very clearly yes. What does that do to the cost structure? Well, it reduces the drilling times significantly, we're evaluating that, but it comes at a higher drilling day cost. But overall, the economics are far better for the -- on the drill side.

The production side, we're now looking at -- and we've spent some time now looking with what we've done in Gabon and what we're doing in Cote d'Ivoire, do we get an FPSO at a reasonable price that can evacuate this oil and at an efficient level. And that's really where the study is right now.

There's a lot of units available in the market right now. And because of the decline in other areas, they're at a reasonable cost. So that's really what we're looking at, have we derisked the drilling position, can we then match it up with an efficient production position. And that's really -- it's like a side bar to use your terms, but it's also looking how we minimize the risk position on the drilling side.

Our next question comes from Jeff Robertson from Water Tower Research.

George, just a quick question in Cote d'Ivoire. When the FPSO gets back to Baobab, how long would it take do you anticipate for production in the field to go back to whatever the full rate will be?

Well, I mean, obviously, we've got the vessel gets back to the field. We've got the contract for the hookup and taking the flow lines back in place, and then we've got commissioning. I mean, I'm -- at the moment in the schedule, we're easily looking at 6 to 8 weeks for that. What we don't -- what we haven't yet looked at, Jeff, is the start-up sequence.

So we've got the commissioning to do, and then we need to look at the start-up sequence for the wells and see exactly which sequence of wells are coming on between the injectors, obviously, and then the producers. So that's something we'll certainly guide to when we come to the next call in early '26. We'll have much more detail on the start-up sequence at that time.

Just one more in Gabon. With the maintenance work that you did in July, what will that do to prepare the facilities, if anything, for the upcoming drilling campaign?

I mean, effectively, I think there, Jeff, we did quite some upgrades to Etame on both power and water handling. So everything is now done and ready for that drilling campaign coming in. But yeah, that's essentially what was done along with the planned -- the normal planned inspection.

[Operator Instructions] Our next question comes from Jamie Wilen from Wilen Management.

Hi fellows. I wonder if you could refresh me on the H2S wells that were shut in a few years ago. How many there were? And what were their -- what was the volume per day? And what is your expectation moving forward?

Yeah, Jamie, we had, I think, three wells out of Ebouri that were [ shut down ] in back in 2014. The production level around Ebouri was between 6,000 and 8,000 a day, and this is from memory, if I've got those numbers wrong, I'll correct them. And as I said, we've got -- we've had 2H flowing now consistently for a number of years. 4H we took on earlier this year and has continued to perform well.

And it's got to be said that we -- our expectation of this well was that it was going to last for 3 months, mainly not because of reservoir issues, but because of the ESP issues. It's an old ESP that has been in that well for probably close to 13 years. And the 5H position, we shut that down when we shut down the whole Ebouri platform.

So the 5H redrill that's coming up in the program this time, that's, for me, one of the most exciting wells that are in the program because it's a redrill back into what should be a crestal position in the field, and we're anticipating some really good results from that well. So with the work on Ebouri and the test work that we've done, it just further enhances our confidence levels to be able to deal with the H2S as and when it comes towards us.

What was the volume of that well when it was producing?

I'd have to check, Jamie, but I think it was probably around about somewhere between 1,500 and 2,000 barrels a day. But my position, this is going to be -- it's -- that's the old well. The new wells are a sidetrack redrill, and it's going to a much higher position in the reservoir structure. So I'm a little bit confident we may see numbers higher than that for that well.

And I think what I'd add to that is George is talking gross, Jamie, all the time. Those are gross numbers.

And ladies and gentlemen, at this time, we've reached the end of today's question-and-answer session. I'd like to turn the conference call back over to George Maxwell for any closing remarks.

Thank you very much, operator. I'd just like to close, we've had a strong third quarter and some good results in the third quarter despite the reduced volumes in net sales because of the government liftings that took place this quarter. The position that we're in coming into 2026 with the execution of our projects leaves us in a strong position.

There are no concerns around where we are in the main capital project around the FPSO for Cote d'Ivoire. That project remains on track, and we monitor it very closely with our partners. I'm very encouraged that we're finally getting going on the drilling campaign, albeit there's a 4-month delay in the rig arriving. But that's very encouraging, and it shows our commitment both to Gabon and our commitment to CDI for our investment.

We've seen strong EBITDAX performance over and above guidance this quarter, which maybe was a bit masked by the revenue. But again, with the lower revenue and higher EBITDAX indicates the company's focus on its cost control during this period of softening commodity prices.

So I'm encouraged that when we come to talk again early Q1 that we will complete 2025 on a successful basis. As you've seen, we've narrowed the guidance to give further confidence to the market as we see our position narrowing to improve the profile through Q4. And with that, I look forward to talking to you again in Q1 2026. Thank you.

And ladies and gentlemen, with that, we'll conclude today's conference call and presentation. We do thank you for joining. You may now disconnect your lines.