An international oil and gas exploration and production company with assets located in Gabon, Egypt, Canada, Côte d'Ivoire, and Equatorial Guinea. VAALCO's asset portfolio combines a mix of short-cycle development projects and long-cycle development and exploration projects 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, I'd like to thank you for taking the time to join us today.
Thank you, Jeff. It's a pleasure.
Let's start in Gabon. Third-quarter production in Gabon averaged about 8,800 barrels per day. George, the last well completion in Gabon was early in 2023, and that followed a full field reconfiguration that was completed in late 2022. You've mentioned this year that production has benefited from some of the operational efficiencies gained and well performance from both the reconfiguration and the drilling campaign. Should we expect some of that performance to have an impact on the way you book year-end 2024 reserves?
The short answer is yes. I mean, the improvement in the field performance that we've recognized through 2023 in our reserves evaluation with NSA and it was recognized partly in our year-end 2023 reserves. So part of that performance enhancement was in our reserves report of last year. However, given what we've seen through 2024, we've seen a very strong performance from the reservoir. We've seen a shallowing of the decline. We do expect that there's some headroom for further incremental improvement in reserves when we do the 2024 CPR at the end of the year.
I know increasing runtimes has been a part of the operational improvement. Can you talk a little bit about how that is impacting the production costs in Gabon?
We went through a major initiative with the reconfiguration and reducing the amount of downtime. So through 2023 and so far in 2024, we've seen a 97% uptime position. Coupled with that, we've also went through a cost reduction exercise in Gabon to try and remove at least $10 million-$15 million permanently out of the OpEx, over and above the OpEx savings that we saw through the reconfiguration in 2022. Now, when we look at that, we're seeing very strong performance from the infrastructure that have allowed us to delay or defer some planned maintenance. We are going to see some increase in maintenance in 2025 just because of the natural cycle of how long that equipment has been in operation since the reconfiguration. But we're definitely seeing some significant benefits, some reduction in the operating costs as a result of these improved efficiencies.
As I mentioned, the last new well was completed, I think, in early 2023. I know VAALCO is preparing for a new drilling campaign that's expected to begin in mid-2025, and that campaign will include new wells at Ebouri and Etame, along with a gas well and an exploration well. George, how are you thinking about sequencing the wells in the program to have an impact on production sometime toward the end of 2025?
Ideally, we would always want to sequence the production wells and the infill wells ahead of any non-productive wells that's potentially the exploration well or the gas well for fuel feed fuel. However, it's not always possible to do that. Equipment and long lead item deliveries sometimes also dictate how we're going to look at the sequencing of the wells. For the initial wells, the first two wells that are going to happen in Etame, they are infill production wells. They are definitely there. Our preference in the sequence is then to move forward into the Ebouri production wells. Those will be long lead equipment dependent. Can they arrive on time? We would move to the exploration well and lastly, the gas well. The gas wells there, we see that we have sufficient fuel gas in the existing well to take us through mid-2026.
It's quite easy to sequence the gas well at the end. The preference is to get the higher production or higher predicted production wells upfront in the program and start to impact that for the Q3 and Q4 of 2025. I think we can definitely do that for the Etame wells. There's a question mark whether we can pull forward the sequence for the Ebouri wells just based on the classification of completion equipment we may need for that severe service position that's going to be in Ebouri .
Are the Etame infill wells a function of some of the reservoir performance you've seen on recent wells or taking that performance and integrating with the seismic survey that you have? Or are they new acceleration wells? Or are they reserve adds? Can you tell us a little bit about what types of prospects those are?
They're a mixture of prospects. There are opportunities for accelerant wells. Some of these have been targeted from where we've looked at from the seismic. Bear in mind that the seismic performance there has been sometimes challenging to interpret, given that we've got to see through the salt position. Yes, I mean, we're expecting as the reservoir matures that we have pockets of potentially attic oil that could be targeted to further enhance the production opportunities. The surety that we're doing in this particular program is having the opportunity of multiple targets from a single wellbore infill opportunity. When we're doing that, it increases the cost a little bit, but it does provide a degree of surety as we drill pilot holes initially to establish exactly where the oil contacts are and then go forward with the completion. We've got multiple pilot opportunities for each wellbore.
That's where we've spent a lot of time evaluating this drilling program to make sure that we greatly reduce the risk of failure.
So it sounds like those wells potentially could add new reserves. Is that right? Did I understand that right?
Yeah, they will add new reserves. Although some of the reserves are already in this because you have to bear in mind we have this program outlined back in 2023, and the program did form part of our 2023 year-end reserve evaluation because we committed to execute. So some of those reserve adds are already in there, but yes, of course, even with what we're trying to do with the Ebouri side and the movement from contingent resource, sorry, not contingent resource, 2C contingent reserves into 1P reserves for Ebouri is a major move that could take place.
Ebouri was taken offline because it had high H2S content in the oil. I think you all have been working on a program to solve that problem, which will allow you to return that field to production and return it to reserves. Would you expect that reclassifying, I guess that will take place after those wells are drilled? Or would you be able to capture any of that in your year-end 2025 numbers?
One would hope we could capture that in our year-end 2025. As I said, I'd like to at least be progressing the Ebouri program in 2025 ahead of the exploration well and the gas well subject to the equipment deliveries. It's really down to our ability to demonstrate our understanding of how the H2S is moving through that reservoir and given the well locations and being able to demonstrate that to a competent person.
The amount of work we've performed on Ebouri , both on the well site with doing the testing to ensure that downhole chemical injection will be sufficient to capture the majority of reserves rather than going to a mechanical process, gives us a lot of confidence that not only have we unlocked that value that's been locked up there since I think 2012, 2014, that field was shut down, but also to give an opportunity to make this much more economic because the cost of the mechanical solution was between $80 million-$100 million. So while we will see upon a successful drilling case on Ebouri an increase in OpEx of a couple of bucks a barrel to deal with the chemicals, you have to offset that against your saving over $100 million of CapEx on the mechanical solution.
Adding that crude stream to the existing mix at Etame, will that have any impact on your price realizations?
We don't believe so, but obviously, as fields mature, there is a change in the crude oil consistency. At the moment, we trade at or a premium to Brent. And some of the points to make clear here, some of the Ebouri crude is already within that blend. So we're having some higher volumes, but we're also anticipating some higher volumes from the Etame field. We don't really see a significant move in the blend position. Therefore, we don't see a significant change in the price point. Where the crude is valuable at the mid to low 30s API, it's exactly at a sweet point for where we sell our crude to the refineries.
George, I know it's still early, and VAALCO obviously hasn't provided any guidance for 2025 yet. But can you share any color on how people should think about the production impact of the drilling program as you move out of 2025 and into 2026?
Yeah, I mean, we obviously, for the infill wells, we've got a range of success outcomes. We've got obviously a number of forecasts on the IP rates for the infill wells and what we expect to see from Ebouri . I mean, for us, this was a, and as I said, we delayed this campaign for 12 months, partly due to rig availability, partly due to pricing of drilling units, and partly due to making sure we had a sufficiently comprehensive program to develop in the Etame field. So we certainly are forecasting on a success case basis that we will have a significant improvement in our current production levels. What still needs to happen is what is the impact of these infill wells over the whole life of field reservoir simulation model and where would that actually impact?
So while we drill these wells and they're going into existing reservoirs, we've calculated where potentially we will see interference in other wells. So we're looking at the net position every time. But yeah, I think where we are, we are making a significant investment. We're looking for a pretty significant step increase in the production from the five development wells that are in this program.
Am I right in thinking that if you add production from this program, putting more barrels through the fixed infrastructure you have, it'll lower the unit LOE? Is that correct?
It's a correct assumption other than part of that production is going to come from Ebouri with a higher OpEx cost because of the chemical injection. So you are going to see that increase on the chemical side. We have seen those higher volumes going through or with those higher volumes going through the revised infrastructure, we're forecasting to keep that level of efficiency. So yes, from a lifting cost perspective, definitely you'll see a lower position. From the OpEx per barrel excluding lifting costs, the balance between Etame and Ebouri , you might just see it being a wash.
With respect to the exploration well, do you anticipate that that prospect or is that prospect an outgrowth of the last drilling campaign, or is it a new idea that you plan to test?
It's been around from the last campaign. It's grown in clarity and certainty on a POSG level from the interpretation of the seismic, and it's like anything when we have these opportunities, the more opportunities you find, and it's about maturing that particular opportunity, so when we look at the exploration portfolio in Etame, and we don't talk a lot about that exploration portfolio in the past because many things have been there and they come and go through that funnel. Some things that are there look really bright and prospective, and they suddenly disappear because they don't fit the map anymore, so this one is our best prospect that we've matured to this point. It really does give an opportunity to a new type of play for us, but it is still an exploration well.
I think it's a testament to what we see in this hydrocarbon structure that we are fortunate to operate in Gabon that after over 22, 23 years of operation, we're still finding within near field opportunities exploration prospects.
Lastly, on that drilling campaign, it includes a gas well, which I think is meant to supply fuel gas for the infrastructure at Etame. How would that impact operating costs?
That is significant. As the field gets older and goes through decline into the late 20s and early 30s, the opportunity to fuel the field for power through field gas rather than diesel is actually significant from an OpEx cost per barrel. So it may sound a little unusual that you're spending $30 million or $35 million to go and drill a fuel well, but it definitely pays itself back when you replace that both from an emissions standpoint and from a cost standpoint, substituting HFO diesel for field fuel. So it's a significant economic benefit to the length of field life that we have in Etame, and it helps stretch it out beyond 2030, 2032.
If we switch to some of the other parts of the portfolio, VAALCO acquired assets in Egypt and Canada in late 2022, and you've enhanced production there through improved field operations and some development drilling. You said recently that you contracted a rig in Egypt to begin a new round of development. George, does that program include both infill and step-out wells in the existing producing areas?
Yes, it does. I mean, what we've looked at in Egypt is we've started with remapping the fields on newly processed seismic. In the north, we're looking at integrating the results of last year's drilling campaign to identify the new infill locations and attractive extension locations adjoining the fault blocks. And we've also done a lot of reinterpretation in Northwest Gharib blocks in the Cairo 4 nearfield exploration targets with good upside potential. So we're looking at how best we can manage, again, a relatively mature asset with looking at past experience, looking at the reinterpretation of seismic, and the opportunities that we've now created through an exceedingly efficient drilling process that makes some of these targets much more economic than they would have been in the past.
I think one of the wells that VAALCO drills since taking over the asset was a horizontal well. Will the upcoming program include any horizontal wells? And are those types of wells needed for the type of reservoirs you're dealing with?
The short answer is no, and the longer answer is no. We have no plans to do further horizontal wells at the moment in Egypt. The drilling campaign for 2025 is designed to identify potential horizontal well targets, but if the reservoir conditions are right, but we haven't really had the reservoir conditions that have indicated that these are necessary at this time. We're very experienced and comfortable applying the horizontal multi-completion technology, but only for the right conditions.
Can you provide some color just around the inventory level that you've identified in Egypt?
Last year, we had a 12-16 well campaign. This year, we're commencing with an inventory of at least 12 firm development wells in the Eastern Desert starting in December 2024. The rigs being stood up now will start drilling in December. I'm looking at appraisal well in the Western Desert in South Ghazalat concession in 2025. In South Ghazalat, appraisal well will follow on. We've got a workover and a refract being done on the South Ghazalat 7B well in December. We'll drill a Northwest Gharib exploration well in 2025 and have three further contingent exploration wells and a whole lot of other contingent appraisal and development wells in this program. We're doing two things. We're starting with a program on our existing development in Northwest Gharib.
But more importantly, we're going back into South Ghazalat in the Western Desert to go back into that well that was very prolific that died out. We tried a mechanical solution workover last year that didn't work, and now we're going back in with a complete recompletion and a refract in December to see what we can do there, but as everyone knows, in the Western Desert, it's very prolific, and we need to spend a little bit more time on that block to see if there's a prize there for us, so the recompletion in December and then the well in 2025.
George, are there any facility or infrastructure issues you need to deal with to accommodate the upcoming drilling campaign, or was that taken care of with the last round?
No, that was definitely taken care of the last round. We don't have any facility constraints at the moment. We've put together, as you would expect us to, we've put together an integrated work program. That means we look at production, we look at drilling, we look at facilities, we look at evacuation. And the integrated work plan makes sure that we have any asset integrity upgrades that are required are there ahead of the execution of the drilling. But at the moment, between our drilling activity, the flow assurance, water handling, and the production increases, that's all catered for within the existing infrastructure.
In North America and Canada, you all drilled a long lateral horizontal well as part of your campaign. And I think you've been very pleased with the results in planning additional long lateral wells. I'm wondering if there's much landwork that needs to be done so that your acreage position can accommodate the length of laterals you'd like to drill there?
Yes, I mean, it does. We've been remapping a lot of the fields based on reprocessing reprocessed seismic. We've acquired most of the land that we required to transition to long lateral horizontals. There are still one or two locations where we may, and I'm going back on my own words here, but we may have to drill a short one mile to keep the land. It's one of the things we've been trying to avoid, but you can't always ensure that you can acquire the land to give you the longer lateral, and sometimes time is against you, so that may happen next year, but about two years ago, most of our land position was in Crown land. Since that time, we've focused on acquiring all the necessary land we need to put that kind of patchwork quilt together to give us the opportunity to drill the longer laterals.
And I think we've developed, been very successful. I think in this year's program and the last year's program, we've drilled wells that have been in the top 10 wells in Alberta. So it shows the level of success. We're currently drilling a well right now in the south. And hopefully, we'll be able to announce the results of that in the near future.
Assuming that well is obviously successful, how much history do you need on a well like that to decide to go forward in that area with incremental development?
Yeah, I mean, it's a difficult one. But normally, we would look to have between two and six months of success to be able to map that and get it into the type curve opportunities that will expand further drilling opportunities in the south. So certainly, we believe this well is going to be successful. And we need to have that tenure of results to extrapolate that out. What this was really there to do, this well was really there to go and prove that that hydrocarbon system existed within a certain type curve. And that's why we need the time to develop and produce that, to establish that. And that then opens that hydrocarbon system up into a greater amount of reserves for the company in the south.
So given it's in Canada, does some of that just overlap with the breakup season when you can't really do much up there anyway?
It might do. Although when we come into, I say we're drilling now, when we come into the turn of the year, it's really when we want to try and drive forward the other drilling programs. We're not going to have enough information to put together a program in the first half of the year for Canada for the south. We'll have to wait to see the results on the production results from this well, and that may come into play for the second half of 2025.
In Equatorial Guinea for the Venus development, VAALCO's continuing to move toward completing the FEED work in advance of reaching an FID. I'm just curious, once a successful FID is reached, can you remind us how much time it might take to actually bring that field into production?
Well, there's obviously, when we look at these opportunities and with the other opportunities the company has, we look at balancing our capital allocation so we don't become overstressed. So that's the first key point is we look at where the near-term oil objectives are. So the basic mantra of our company is we know we have to invest dollars in the ground, and we want those dollars to be in the ground for the shortest term possible before they go back. So that means we have to balance our projects to the ones that are going to return that dollar in the shortest period of time. So when we look at where we are in Equatorial Guinea, where it's a complete greenfield site, we look at a number of things.
One, we know we have proven hydrocarbons, but we don't have a proven hydrocarbon producing system, unlike Côte d'Ivoire, unlike Gabon, unlike Canada, and Egypt. So what we then have to establish is how long is that dollar going to be invested, and how do we make sure we have that surety of return? And that's why we embarked upon the feed study. We embarked upon the feed study to see that the initial CapEx levels were high. How do we reduce that CapEx level to ensure that the project doesn't demand so many dollars from us? And again, if we can either shorten the time the dollars in the ground or shorten the amount of dollars that we have to put into the project, that's always economically efficient for the company.
The feed study will come out and establish whether we can move $130 million-$150 million of CapEx into OpEx through a lease buyback opportunity for the production facilities, so that's what's there to establish in conjunction with a seabed survey to make sure that the location we want to drill from and the location we want to produce from on the shelf is suitable to hold the structures that we plan to put there, so far, in the feed study, I can say right now in late November that there's nothing holding us back. There's no key impediments to what we see at the moment, although the seabed survey still has to be undertaken, but from what we see in the marketplace, the opportunity to move CapEx to OpEx does exist, and we expect to complete that feed study in the early part of Q1.
What that then does is completely change the economic viability of the project and the risk profile of the project. We now still see the oil is still there. The production capacity of the structure at over 17,000 barrels a day is still there. But the risk amount of dollars we have to invest in it to extract that oil has reduced by 50%. And that really is a testament to the FID. And we can then move forward during 2025 and early 2026 to establish the production facilities to then allow the end of the drilling program in Gabon an opportunity to perhaps commit to a drilling program late 2026 after the Gabon program to go and drill in Equatorial Guinea to coincide with a 2027 production.
When we look at the constraints on the company's cash flows, when we look at where we are in existing producing hydrocarbon systems such as Côte d'Ivoire, where we've got the vessel going offstream and we've got to invest dollars there, the timing and flow of these projects is very important so that we have a continual flow of investment, but the outputs and production increases are augmenting at different times. The beauty of having a balanced portfolio is each one of these projects support each other in their timing. That's why the timing of these events are very key. We spend a lot of time planning and project managing these to make sure that we don't overcommit the company and we can see the production increments coming in in time for the next investment cycle.
From a technical standpoint, with your PSC in Equatorial Guinea just moving dollars from CapEx to OpEx, does it have an impact on the economics just under the contract terms you have to VAALCO's benefit, or is it more about the spending cycles?
No, it's not just the spending cycle. I mean, the spending cycle obviously is very important because we all want to get the project done. We want to get it done in the most efficient way for the company overall. But it's not just that. When we look at the opportunity in Venus, and of course, once we have the infrastructure there and we're producing from Venus, there's always tieback opportunities in the likes of Europa, which is about six kilometers away from where our planned location is. But the key here is that it's a relatively small accumulation. It's 25 million barrels that can be evacuated. This gives it a relatively short cycle, probably somewhere around 48-60 months, so five years in you've evacuated that position. Now, it is important that on an OpEx basis, you can recover that in that five-year period.
If we're on a CapEx basis, from a tax efficiency standpoint, you'd have a legacy tax pool out there that couldn't be recovered at the end of that production cycle for Venus. Now, what is the upside opportunity that we look at is that, okay, there may be more oil there than we anticipate. There may be an opportunity to tie back Europa. There may be something else. So we would always want to retain the ability to purchase the production equipment should the opportunity go beyond the initial five-year cycle that we see.
In Côte d'Ivoire, the operator is getting ready to take the FPSO off station for a scheduled maintenance and refurbishment program in anticipation of an expectation of a 2026 drilling program. George, is the maintenance and upgrade program, will that have a material impact on costs when the FPSO returns to the field?
We don't really think so. I don't think we'll have to see a significant cost reduction. What we will see is an extension to the life of the vessel. Certainly, the newer the equipment, the more efficient they will be in processing. So we will see some processing efficiencies. But at this early stage, it's impossible for us to quantify exactly what the impact of that processing efficiency would be on OpEx. But really, what we've got here is a vessel that's been designed fit for purpose for this type of field. It's come to almost the end of its useful life in its current structure. It needs to be refurbished in order to extend that life. And its asset class through 2038. So it's really just allowing accessibility for production between 2024 and through to 2038. I do believe there will be some efficiencies.
But as I say, that's mainly because we're going to have more modern and more efficient processing kit on the topsides.
The equipment will be able to accommodate the 2026 and future development?
Yeah, on a capacity basis, there's no concerns. I think for what we see, when we evaluated this, and we've evaluated this independently from the operator, we see the opportunities in phase V drilling and potentially phase VI. We've just commenced seismic work in this quarter to look at better imagery around the CI-40 opportunity. So we see a lot of opportunity for enhanced production, but we don't see a restriction in the production capacity. So once the vessel comes back, and this is from our own numbers, not from the operator's numbers, on our evaluation, the future developments inside Baobab, phase V, phase VI, CI-40 can be handled by the capacity that's going to come back within the FPSO, the MV10. So there's not going to, once it's back on station, we don't see any capacity constraints on the production.
It would be a great problem to have if we did, but at the moment, we don't see that.
As we've laid out today, the existing asset portfolio exposes VAALCO to reserve and production growth in every country that it operates. I know the 2025 capital program and guidance won't be finalized until sometime early in the first quarter of 2025. At the end of the third quarter of 2024, VAALCO had about $90 million of cash and zero long-term debt. George, you addressed some of this a few minutes ago, but when you think about the entire portfolio and capital needs and the kind of cash flow, how do you balance all of those needs and spending sequence with your goals to be able to return cash to shareholders through the fixed dividend program?
Let me start with the fixed dividend program. When we took over this company three years ago, we initiated a dividend. We bought, as we enlarged the company through acquisitions, we've doubled that dividend. We've made the commitment, and we do publish this all the time based on certain oil prices, and our commitment through to at least 2026 and beyond that that dividend program will stay in place. Of course, the board ratifies every quarter, but we have no plans to change or modify that dividend in any way. That is a commitment we've made, and it's one that we have upheld through the last 12, 13 quarters.
I've said this before in presentations that our mantra is that the dividend and budgeting that dividend and making sure the cash is available for that dividend is just as important as budgeting the drilling and budgeting the G&A and the geoscience teams that we budget every year. It sits right up there and ranks just as high as our investment development projects do. When we look at that, that comes within the mainstay of our underlying budget. Then we look at the investing opportunities over and above that on the CapEx side. As I've mentioned earlier, we always have to look at how do we balance this position, how do we ensure that the company, through its existing cash balances and through its available credit lines that we have, don't get ourselves in an area where we're stretched or pinched on our ability to execute.
And I go back to when we first took over this company and where we started to put protections in place, whether they're costless collars on hedges or whether they're other protections we put in place to ensure that regardless of where the oil price is at certain positions, once we get into a project, we have a position through our production opportunities and potentially our hedging opportunities to ensure that we'll always be able to fund that execution. And that's the key. We've got to try, and we have been successful in de-risking those major projects. We went through it in 2022. We spent over $260 million reconfiguring the field while doing a drilling program. We're going to be exactly the same scenario next year where we're doing a drilling program and reconfiguring a field in conjunction with our partners, CNRL.
So we take the appropriate coverages to minimize that risk to ensure that that execution can take place without getting the company in any significant difficulty. And that's what comes down to balancing your projects and balancing the production. And we can see we have a depleting resource in any of our operations. And in order to arrest that depletion, it requires investment. So you can go through periods of lower investment cycles, and we've seen that with VAALCO for 2020, late 2023, 2024 has been low investment cycles. Then we'll go through a period of a higher investment cycle in 2025. But the flip side to that higher investment cycle is much more production coming out in 2026 and 2027. So it's all about managing that position and where we're going to be tight on cost control. We're going to be tight on project management.
We're going to be tight on the project timetables to make sure we deliver. That's the focus, the key focus for 2025 for us.
George, I know as these 2025 events crystallize, I think we'll have plenty of opportunities to host another fireside chat to talk about the definitive plans. So I think we'll leave it there for today. I'd like to thank you very much for taking the time to join us.
Thank you much, Jeff. It's a pleasure as always. I look forward to talking to you again in Q1.
Thank you.
Thanks. Bye-bye.