VAALCO Energy, Inc.

Good day and welcome to the Valco Energy second quarter 2026 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star then two. 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 FPNA. Please go ahead.

Thank you, operator. Welcome to Valco 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. During our question and answer session, we ask you to limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. 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. Falco 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 two 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 Côte d'Ivoire position. We were named operator with a 60% working interest in the Kisapo field on the CI40 block that had two discoveries drilled in the field and is located only 8km from Baobab. We are actively evaluating and processing seismic with our partners in Niossi Marine and Gaduma Marine blocks offshore Gabon and on our exploration block CI705 in Côte d'Ivoire. The Baobab FPSO successfully completed its refurbishment and the field resumed production in June as planned. At Itami, we continued 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 Côte d'Ivoire. We were excited to have production resume in Baie-Bab in June 2026. As you know, in line with the project timeline, the FPSO at Baie-Bab ceased hydrocarbon operations in January 2025, spent a year being refurbished in Dubai, and returned to Côte d'Ivoire in April 2026. We are very pleased how well the FPSO refurbishment went and that it was completed within the initial timeline expected. All producing wells online and production is slightly above our pre-startup forecasts, 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 non-operator 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 programme in Baobab in Q3. This programme includes four producers, two or three injectors and two workovers providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension to the licence to 2038. The current drilling plan on 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 one well to be on production by year end. With that said, production and sales uplift from the drilling programme at Baobab will not make a significant impact until 2027. In February 2026, in accordance with the CI40 PSC, Valco and Petrosy elected to participate in the development of the Kisapo field. Valco was confirmed as operator with a 60% working interest in the Kisapo field on the CI40 block just 8km 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 de-risk 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 Côte 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 Albion sections. We have met all current work commitments on the block and have been granted a six-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 Côte d'Ivoire prior to April 2024, so in less than two years, We are excited about the prospects in Côte d'Ivoire and their ability to help us achieve our production growth targets over the next several years. Moving to Gabon In the fourth quarter of 2025, we began our Phase 3 drilling programme. I would like to note that working interest production in Gabon in Q4 2025 was 7,743 bars 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 Itami field, as well as access deeper potential in the dental and test and exploration prospect from the platform. The program began with the drilling of two pilot wells in the Itami field. One of these was sidetracked and completed as Itami 15-8 development well in the 1V fault block. This well came online in late February, so our Q1 production results had only one 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 Etanid platform to drill an exploration prospect in West Etan. While the well encountered 10 metres 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 well bore was utilised and sidetracked in the upper portion of the well to drill the ET14-8 development well in the main fault block of Itami that was de-risked from the results of the earlier pilot wells. In late April, the Itami 14-8 was brought online after encountering 325 metres of lateral net pay in high-quality gamba sands in an attic position within the main fault block at Itami. The 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 programme at the Itami platform, we moved the rig to the Iburi platform where we drilled the Iburi 5H development well. This well had 300 metres 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 75-80% 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 modelled. We are currently evaluating this well performance with a view to remodelling the aburi 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 SEMP platform and drilled the ETBNM3 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 SENT platform and is drilling the ETSEM3 pilot hole. The pilot is designed to aid in landing the lateral producer, test the original field oil-water contact and also evaluate the potential of the underlying dental formation. Once the pilot hole is completed, a horizontal development well is planned near the crest of the central fault block in south-east Etam in Tugamba 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 work-over 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 Iburi continue to perform well with the chemical treatment and we do not want to take these wells offline to perform maintenance work-overs 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 Nyosi Marine and the Gaduma Marine, we continue to work with our partners on plans for the two 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 this 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 Itami and Disafu, we are excited about the future possibilities for these blocks and will continue to mature prospectively 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 two 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 programme, which contributes to minimising costs. Given these strong results, we resumed the drilling programme 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. They are further expanding the scope of the Egyptian drilling programme 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. They also plan to continue optimisations, workovers and re-completions 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 gazolat 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 finalisation 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 risks and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a sub-seed 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 our programmes 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 would 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 in our enhanced portfolio and a proven track record of success these past few years have instilled 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 39 cents 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 unrealised 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 costs of an exploration well at West Itami that was determined to be unsuccessful and additional seismic costs at the Nyosi and Gduma 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 two partner liftings in Gabon for around 900,000 barrels gross each. While the production came back online in Côte 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. 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 administrative expenses was primarily a result of a £1.9 million of non-recurring 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 programme which is more consistent over a rolling time horizon. Our strategy prioritised downside protection to safeguard cash flow to help fund capital commitments for the Côte d'Ivoire-Beaubub FBSO refurbishment, the Gabon Phase 3 drilling campaign, our debt servicing and the Scheer-Tever dividend programme. In March, oil prices spiked and we had both realised and unrealised losses as we marked to market. This is re-evaluated at the end of each quarter and the pricing at June 30th declined materially from March 31st, 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 and 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 favourable all price adjustment as a result of the change in value of the Government of Gabon's allocation of profit all between the time it was produced and its present marked market liability. In Q1 we had estate lifting in Gabon which settled our tax position. and we do not see another state lifting in 2026 with our cost pool maximised with a spend on the drilling programme which is first to be recovered. Similarly, we do not see a state lifting 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 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 Côte d'Ivoire. Thus far in 2026, Côte 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 non-essential capex. We have seen excellent performance from our drilling team in Gabon, and we've seen each well to date come in below its pre-drill, budgeted approval for expenditure. This together with some Itami 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 envisage 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 $13 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 Falco paid another quarterly cash dividend of six and a quarter 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 will 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 Biobab 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 Côte d'Ivoire, with the Beobab 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 two 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 a 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 quarters 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 are 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 and $4 million for Q3. This is primarily seismic processing work in both CI705 as well as similar processing work by our partner in Niossi and Gduma blocks. As George discussed, we are dropping the offshore work-over guidance to zero 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 is savings. As George mentioned, we are adding wealth to our Egyptian program, but maintaining our full year capital expenditure midpoint. For Q3 2026, our capital spend is projected to be between $75 and $115 million as we continue the drilling campaign in Gabon, prepare for the drilling campaign at Biobab, 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 favourable 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 on the telly in Gabon to field gas. We believe we would remain well positioned to continue executing our strategy of growing production and reserves while adding meaningful value. Early 2027 will continue to see growth in our production, sales and margins as our Code of War 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 programmes in Côte d'Ivoire, Gabon and Egypt. The restarting of the Bay above field in Côte d'Ivoire in June, the wells in our Gabon programme 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 productions 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 a decade. There are numerous macro events that we cannot control, but the things that we can control We are actively working to continue to deliver strong results that will fund our successful capital programmes 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 will 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.

Thank you. We will now begin the question and answer session. To ask a question, you may press star then 1 on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then 2. Please limit yourself to one question and one follow-up. At this time, we will pause momentarily to assemble our roster. The first question today comes from David Rown with Stifel. Please go ahead.

Great. Thanks, guys. First of all, 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 re-completed as a producer.

Yeah, just to add to that, I mean, we logged obviously on the way down and our subsurface people are looking at that. But yeah, 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, but 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.

Yeah.

Hi, David.

If you look at the first half of the year, I mean, this gas bill was brought online at the very end of July, so it's effectively seven months. The key one here is the tele, 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 onto gas. Now, there are some elements of it on the platforms themselves, but the big one really is the tele. And that's roughly about 300 to 350 cubes per month in volume. So, you know, 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. You know, we were 58% of that. We have seen increasing pricing on that cube for diesel fuel throughout the first six or seven 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.

Yeah, I mean, so some of our wells are on gas lift with a compressor. And under diesel, we just couldn't operate at the high enough RPMs to maximize or optimize a 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 enhanced oil recovery numbers coming from these wells.

Right, that's really clear.

Thanks, David.

The next question comes from Staphon Flucco with Octus Advisors. Please go ahead.

Hi, James. Thanks for taking my questions. 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 the 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 Terminus of activity given the change of the work program, whether it's well, whether it's this issue that you described around the lower pollution efficiency. I think we have 93%. What's happening? That will be my first question. Thank you.

The main issue there comes down to the 5H well that I had mentioned earlier on the call today. The level of decline in that well was far higher than we anticipated and modelled. 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 modelled, 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'd have had it at much higher production rates and that's the main reason for the decline.

Okay, that's great, thank you. And the second one is on COSIPO. I think you had 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 FTP 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 so we could pull out all the stops 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, PTC, we were lobbying the DGH to say, look, in order to get this as accurate and as good as possible, we'd really look for a six-month extension to the submission deadline, which they agreed to. And that's why 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 FTP document for submission. Okay, that's clear. That's great. Thank you very much. Thank you, Stephen.

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

Thank you. Good morning. George or Ron, can you talk a little bit about the cost structure at Balabob and how, with production rising into 2027, that might impact Valco's overall cost structure?

Yeah, 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 two things. The operator's 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 a 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 cost that we have in our portfolio and as we go through 2027 that's only good news for the overall

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 two 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 cargo. So that's why if you look at our Q3 cargoes that we've got in Gabon, are going to be probably 600,000 gross cargoes rather than the 900s that we had in Q2. And that's specifically people are waiting to the last minute because they're always thinking that Brent's going to fall in relation to any good news coming out from either 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.

Thank you.

Again, if you have a question, please press star then 1. The next question comes from Bill DeZellum with Tietan Capital. Please go ahead.

Thank you. Ron, would you please circle back to the cost savings 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 millions?

Yeah, no problem Bill, we can do that. So effectively what you're looking at is basically a cubic litre is 1000 litres of diesel. That's been priced, I would say in the first half of the year, our average is probably about 1500 to 1550 bucks per cube. What you will see is from a gross basis, that's a reduction per month of about $5,000 to $600,000 per month. And of course, we're 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 our bill.

Great. Thank you for that clarification. 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.

Yeah, I think I would point you back to our investment deck that we went out on our non-deal roadshow over the last two months and we put some forecasts 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 five 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. Thank you. And I'm going to squeak 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?

So 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.

Yeah, I mean, I think I mentioned Bill and Nicole earlier. We're going to have to, because 5H decline was accelerated Beyond our modeling position, we're going to have to rework the geomodels. And probably over the next four or five months, we'll have a much better predictability. But the performance of the downhole injection and surface injection scavengers has been extremely good. And the breakthrough of what the scavengers are dealing with on H2S per ppm continues to be lower than our predicted models.

Great. Thank you. And 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 startup versus when you took the field down? Is there an initial pressure benefit that you're experiencing?

Yeah, there is flush production coming through and we expect that to continue. We're probably running around 16,000, 400 or 500 barrels a day gross production, which is about 2,000 a day more than the original number that we were using or we had prior to shutdown. The wells themselves came on extremely well and smoothly. There's obviously a concern after wells being 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's very cautious about opening those wells completely up. So yeah, it's good news.

Congratulations, and thanks for taking all the questions. No problem. Thanks, Bill.

We now have a follow-up from Stéphane Flucot with Octus Advisors. Please go ahead.

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? Thank you.

Yeah, we're still receiving some of the data sets so it's probably on the size of the prize around NIOSI and Gduma, I mean, 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 CI705 because obviously we've got a decision we'll 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 asset that we operate. But for Niosia and Goduma, it's likely to be well into 27.

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

Can you repeat that question a little bit?

So I was looking at... So in Q3, 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 we might have a very strong quarter in terms of sales, in terms of listings in Q4, offsetting Q3?

Yeah, yeah. I mean, if you look at Q4 at the moment, the way we're applying, we're seeing... The next question comes from Jamie Weiland with Weiland Management. Please go ahead. Hi, fellas. Wonderful results. But a question on taxes moving forward.

Can you tell me what the cost of oil

is in Gabon as well as Cote d'Ivoire. And how much of the next generation generated pre-tax profits are going to run under VACO?

Okay, Jamie, I'll do my best to answer that question in relation to obviously the taxes and U.S. GAAP. First and foremost, in relation to the cost pools, 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. And I think we've communicated this in relation to the non-deal roadshows. That Gabon cost pool should see us through, again, The big question here always is going to be where Brent lies. Now, if Brent's $100 per barrel, then it accelerates the recovery of that quicker. But if we look at long-term pricing, maybe in the 70s, we see that Gabon cost goal being pretty robust right through 2027. So, again, minimal state listings, you would think, in 2027 at those prices. CDI, we've probably got multiple years worth of shield in relation to the cost oil. So you're probably looking at about three years before the profit oil really creeps up in CDI. Obviously, when you look at US 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 US GAAP there is to smooth out these peaks and troughs. So your P&L and your actual cash cost on tax are completely two 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 two or three years from now.

Great. Thanks, Rob. Appreciate it.

Thanks, Jamie.

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 a non-deal 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 should celebrate a great set of results for Q2, great operational performance by our drilling team here 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 Rowan 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 poll. Thank you.

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