VAALCO ENERGY INC /DE/ Q1 FY2025 earnings call

Financials

• Q1 2025 net income was $7.7 million ($0.07 per share) and adjusted EBITDAX was $57 million. NRI production was 17,764 barrels of oil equivalent per day, working interest production was 22,402 barrels of oil equivalent, and NRI sales were 19,074 barrels of oil equivalent per day, all at the high end of guidance.

Capital Spending

• Cut 10% from 2025 capital budget due to softer commodity pricing; long-term projects like Cote d'Ivoire FPSO and Gabon drilling continue.

Safety

• Egypt had no lost time incidents in 2024 and 2025, with over 4.3 million man hours without an incident.

Acquisitions

• Secured Cote d'Ivoire asset via Svenska acquisition in April 2024.

In Cote d'Ivoire, the FPSO seized hydrocarbons production on January 31, 2025, and the vessel is en route to Dubai for refurbishment; significant development drilling expected in 2026. In Egypt, 7 wells were drilled in Q1 2025 with an average initial production rate of about 120 barrels of oil per day, and no lost time incidents since 2024. In Gabon, there were positive production results, a drilling rig was secured for a Q3 2025 start, and the Ebouri 4H well was producing around 1,000 barrels of oil per day in Q2. In Canada, 4 wells were drilled in 2024, and a well in Southern Acreage drilled in Q4 2024 had initial flow of ~200 barrels of oil per day; no drilling planned in 2025 due to commodity price uncertainty. In Equatorial Guinea, front end engineering design study is ongoing with FID expected in 2025.

Full Year 2025

• Capital budget reduced from $270 million - $330 million to $250 million - $300 million, but full year production and sales guidance remains unchanged.

Q2 2025

• Expected capital spending between $65 million and $85 million. NRI production expected to be between 15,400 and 16,800 barrels of oil equivalent per day, and sales expected to be from 17,800 to 19,300 barrels of oil equivalent per day.

Hedging

• Added additional hedges: 70,000 barrels of oil per month hedged in Q2 with a floor of $65, 160,000 barrels of oil per month hedged in July with a floor of ~$65, and 60,000 barrels of oil per month hedged in August and September with a floor of $65; also gas hedges amounting to 75% of anticipated gas production from May to October.

• Commodity price volatility could impact discretionary capital spending and project timelines. - Drilling campaign in Gabon timing dependent on rig availability. - State liftings in Gabon and Cote d'Ivoire affect working capital.

Q: George, can you comment on the production profile at Gabon over the back half of 2025 and how it fits into your guidance? And I'm wondering if you have any downtime in the numbers that would be caused by the drilling campaign that you'll start in the third quarter?

A: Yes, we don't have any significant planned downtime related to the drilling program for 2025. However, we do have planned preventative maintenance downtime in July. We do see a slight uptick in production towards the end of Q4, which is the delivery of the first well that should be back on production in Q4, but within our guidance, there's not a significant amount of production included from the drilling campaign.

Q: In NCI, can you talk at all yet about how the development drilling campaign starts to look in 2026? And are you looking for are you and the partner looking for a rig there? Or when might you expect to start that? I know you'll probably talk about that in much more detail next week.

A: Yeah. We have some more detail on that next week. Obviously, the Phase 5 drilling is scheduled to start midyear 2026. The operator is actively working on securing the rig, and we'll wait for the operator to make that announcement as and when that's concluded. But right now, everything is on schedule for midyear 2026 for that campaign.

Q: Again, in the context of oil price being lower and a lot of activity coming in 2026, 2027, especially Gabon, [Indiscernible] and Cote D'Ivoire, EG. If all for us were to remain low, I was wondering how you would rank the project or how would you prioritize those projects?

A: Okay. Well, it depends obviously what you classify as a low oil price. Obviously, we've always been sensitizing between around $65 when it comes to our dividend, when it comes to our capital project. And as you're aware, Stephane, particularly in Africa, the PSCs are extremely forgiving on low oil prices and in many cases remain very economic at low oil prices as your cost of entitlement increases. So when we look at the priority of projects, obviously the anything that can be enhancement of production through existing facilities in Gabon or in CDI is much more economic than a Bluewater development. So that being said, the biggest blue water development we have would be in Equatorial Guinea. And as we've already communicated to market that particular project given its short tenure of up to 60 months of production and the terms of that PSC do make it very attractive. So the bolt on opportunities would obviously what we would look at if oil prices fell below the $60 levels on a longer term basis. But when we did do the analysis of the only Bluewater development we have on EG, we did sensitize that down to $50 when we did it that time. Now the other thing we haven't seen quite yet in a lower oil price environment is the service and the equipment market moving towards lower prices to enable those developments to be far more economic. So if there were a sustained low oil price environment, we would expect to see on the service side a corresponding reduction in the cost that would support further economic development even at lower prices.

Q: Ebouri seems to be going very well, $1,000 a day continued in Q2. How does that compare with your expectation? Is it better? As soon as it's in line and what does that mean for the developments in terms of economics?

A: Okay. It doesn't mean anything. I mean, Ebouri 4H was we took it online in order to get further information on the reservoir performance, further information on the H2S concentrations. And one of the things we've always cautioned about 4H, this well was shut in for about eight years, nine years and is still running on the older versions of the ESPs. So we've taken advantage of the resilience of that well to continue to produce beyond our testing expectations. When we look at what impact does it have on the redevelopment of Ebouri, it just gives us further information and a greater degree of confidence that the solution that we've established on downhole chemical scavenging is going to be more than sufficient to continue that development in Ebouri. So it's a great boost to Q1. It was unplanned. And for our guidance, 4H continues to produce, but it's also something we've taken out of our guidance because it really is just a test well.

Q: Firstly, on Gabon, are you able to give an indication of how big the working capital swing later in the year will be as the government lifting is absorbed? Looking at the difference between your sales and your production numbers, it looks to be about $20 million or so at 1Q oil prices. Secondly, another question some broader question on working capital. We've seen reasonably meaningful outflow over the last two years now. I think cumulatively since beginning of '23 is total of $49 million of working capital. So I'm interested in, again, coming back to my first question, how much of that is the Gabon lifting? But also if there's a chance that some of this working capital is structural that it won't actually come back into the business in the next -- over the next sort of 9 to 12 months or so?

A: Chris, it's Ron. Thanks for that. The let me take Gabon. As you can see in Q1, we had the state lift in February. And you can see on the earnings release that the cash equivalent value for that oil lift for us was just over $30 million. There was also coal lifts, both partner less and state less for obviously CDI in Q1, too. And I think that's about another $1 million. So we actually paid cash taxes through those oil less of about $31 million in the quarter. And that really is the outflow or driving the outflow in working capital in Q1. We had some receivables collections, which would obviously helps minimize that overall impact. Now what that will do is effectively that really represents our taxes for the year, we believe, in Gabon and there'll be nothing in CDI because we're out of production in 2025. So what you will see is your foreign tax payable and the balance sheet start to grow over the next, the coming months, six to nine months. So if anything, it's going to be a working capital improvement, Chris, because we won't have a state lift until into 2026 in Gabon and we certainly won't have a state lift until 2026 in CDI. Hopefully that helps answer that question.

Q: Thank you very much. And can I just have a follow-up on Egypt, please? You've got your $32 million back in the quarter from Egypt, which I have to say very well done. Does that represent all of the sort of the aged receivable that was outstanding that you'd managed to get reclassified, I think it was in third quarter of last year, reclassified as a payable. So it looks like you've got most of that receivable issue in Egypt resolved now. I guess the question is, if that's been resolved, does that mean the Egyptian government is expecting you to put some of that back into more CapEx in Egypt because obviously that would be the quid pro quo, but it feels like at current oil price that isn't probably what you ought to be doing?

A: Again, great question, Chris. The situation in relation to Egypt. First and foremost, let me just make sure and clarify. The movement of $32 million I think you believe you see in the cash flow is in relation to the contractual backdated entitlement, which at one point in time was over $60 million. We've managed to collect the bulk of, in fact, all of that over the last year and a bit. Now what I would say is we haven't seen a $30 million reduction in Egyptian receivables in the quarter. The overall position on receivables improved about $8 million or $9 million because although there is payments and offsets going against that contractual backdated because it's the oldest, your current receivables are actually there's a detrimental issue there. So net net, Chris, I just want to make sure that people understand the receivables did not come in by $30 million they came in by closer to $10 million. Now what that also means is, as you know, we started drilling in the end of 2024. I think we completed two wells in Q4 2024 and we've been drilling in Q1, and I think we completed about five wells in Q1. That current campaign, I think, is somewhere between 12 and 15 wells, should be completed by the end of Q2. So we will be in a situation where we've met our contractual requirements and indeed our work program that we agreed with EGPC. And I'd just again like to thank our local team who are doing a great job with EGPC and making sure that everyone at the end of the day are aligned to the verbal agreements that we have with one another.