Jeffrey Robertson : George, you talked about incremental acquisitions. And with the TransGlobe acquisition in 2022, which added two more countries to VAALCO’s portfolio with a little bit different cycle times in terms of the project lives. Can you talk maybe generally about what kind of what characteristics of an acquisition fit VAALCO in its current profile as opposed to what you might have been looking for a year ago?
George Maxwell : Yes. That’s a good question, Jeff. I mean first and foremost, the acquisition portfolio to — for us to go and action anything, it has to be exceedingly compelling, particularly where our stock price is at the moment. And as I mentioned earlier, with a 2P reserve valuation of PV-10 of over $800 million, we’ve got a little bit to consider more investment in our stock buyback before we really go into a large acquisition. But part of the drive behind that and the drive behind the TransGlobe acquisition was twofold. One was diversification and derisking the revenue stream. And the second thing was the reserve base, so we have a longer life platform for the company. So the — when we look at the opportunities that are in the market at the moment, first and foremost, unless it’s in our backyard and we are going into a new country, we’re looking for producing assets.
We’re looking for assets that will immediately start to contribute to revenue and cash flow. And in addition to that, assets that fit our skill set. Now our skill set has increased considerably since the acquisition of TransGlobe to include a lot of onshore expertise as well as shallow water offshore. And with that, similar to the driver for TransGlobe is to ensure we have a 10, 15-year life span around these reserves, so we have the longevity to report forward.
Jeffrey Robertson : And a question, and it sounds like the answer in terms of the free cash flow profile that you mentioned, Ron, with the capital program in ’23 weighted to the first half of the year in Egypt, is that imply the production benefit from that capital starts to impact second half of ’23 and therefore, you have growing production and less CapEx, therefore, more free cash flow?
Ron Bain : Yes. I would say you’re definitely going to have an impact on Q1 on free cash flow with the drilling underway, and we’re already seeing some tangible production from that. So what I would say to that is you’re very much correct, Jeff, in modeling it that you’ve got a weighted part on your CapEx to the first half of the year, as we stated. So free cash flow will be impacted by that in the first half of the year and generating a lot of free cash flow from the second half of the year.
Operator: And our next question will come from Charlie Sharp with Canaccord.
Charlie Sharp : Yes. Thank you, and good morning, gentlemen. Appreciate the presentation. Just a question, if I may, on the production expense. I guess two questions really on it. Firstly, I think applying the lens of 136 million to 157 million, can you give us an approximate breakdown geographically of that production expense? And then secondly on it, just looking at the production range that you’ve indicated, if I assume that the production expense range is related to the production range, that turns out a $18 a barrel production expense. And so I just wonder where that 16 to 20, which you highlight in the presentation, where that comes from? Is that related to production or partially related to production? Or are there other factors?
Ron Bain : Okay, Charlie, I think I can take those. When we look at the overall guidance for the year, we assume production and sales are going to be the same for the whole year. And so most of the year, production expense a barrel of oil is actually done on a sales basis. So that’s why those particular statistics look the way they are when you calculate them, it will be based on effectively the sales models. When I look at the overall composition of that full year guidance on a per barrel basis, 21 to 27, I guess I would probably point you to, to a certain extent, to the netback slide, just for confirmation of those costs. I know that they’re blended in there. But when we look at the overall composition of the cost by area, the operating cost by area, by far, the majority is obviously going to still be in Gabon.
I would say that that’s probably somewhere between 50% and 55%, Charlie. The remaining 45%, I would basically put that to Egypt and Canada, obviously, I would wait that 40% in Egypt and the remaining part in Canada.
Charlie Sharp : That’s very helpful. And one small follow-up, if I may. You indicated that you’ve made some progress in terms of I think you described them as documentation on Equatorial Guinea and that there should be another update in Q2. Can you just say a little bit more about what that means, documentation? And in Q2, are you going to be able to give us some sort of flesh around the details of the plan as you see it at the moment to commercialize Venus at least?
George Maxwell : Okay. Well, I can say a few things, Charlie. One is that a few weeks ago, we had some excellent meetings here in Houston with our partners and with the government, emanate. In those meetings, what we’ve been working on for some time is whilst we were looking at the plan of development and where we were in Q4 with that plan of development and we got the plan of development approved. We still had a number of issues outstanding in relation to the amendment to the production sharing contract with regards to equity percentages that were historically not signed off properly and one or two other issues. So we basically had two PSC amendments outstanding with the government. Both of these amendments were executed in March and allow us to move forward to then finalize amendments within the joint operating agreement between the partners, but at the moment remain outstanding, so I can’t go into the details of those.
But we do expect those to be executed in the very near future. When we look at the development itself, we have in Q4 of 2022 we went through a peer review of that development, essentially looking at each of the gating criteria from the long lease drilling program through to the plans of doing an extended DSP and the topside facilities. So we’re currently optimizing that with the input of the peer review to improve both the efficiency of the development and the — reduce the complexity of the development. So when we look at where we are in 2023, the majority of the work that we’ll do in relation to Block P for ’23 will be finalizing the studies work in coming up with the development plan as optimized. That may include looking at drilling all the wells at the same time as opposed to drilling them staggered just because the economics of moving the rig in there and leaving it there to drill the two producers in the water injector makes more sense.
But — and then looking at the top side. So we’re looking at what real activity will happen in 2023, I expect we will do — complete our seabed survey to ensure that we can locate the mop and the rig and the location that we plan. We’ll finalize the construction and engineering phase and be able to then put a more detailed timeline on the development in — towards the end of this year. It certainly is planned that when we look at the drilling program for 2024, to utilize that same unit to drill the wells for us in 2025, early ’25 for the Venus development.
Charlie Sharp : That’s terrific.
Operator: We have time for one more guest with questions, and we will take questions from Bill Dezellem with Tieton Capital.
