Ladies and gentlemen, thank you for standing by. Welcome to the VAALCO Energy First Quarter 2023 Conference Call. [Operator Instructions] This conference is being recorded, and a replay will be made available on the company's website following the call. I would now like to turn the conference over to Chris Delange, Investor Relations Coordinator. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to VAALCO Energy's first quarter 2023 conference call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights along with operational results. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. 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. I would like to point out that we posted a first quarter 2023 supplemental investor deck on our website this morning that has additional financial analysis, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release, the presentation posted on our website and in the reports we file with the SEC, including the Form 10-K and Forms 10-Q. Please note that this conference call is being recorded. Let me turn the call over to George.

Thank you, Chris. Good morning, everyone, and welcome to our first quarter 2023 earnings conference call. We have had a lot to review in each of our calls over the last year, but today's prepared comments will be pleasantly shorter. We have made significant progress integrating TransGlobe into VAALCO and are now focused on optimizing production, managing our costs, fine-tuning our operations, and allocating capital to drilling, future growth plans and shareholder returns. This was our first full quarter of reporting as a combined company following the transformational combination with TransGlobe, which has built a business of scale with a stronger balance sheet and a more diversified production base. I would like to point out some key highlights and accomplishments for the first quarter. We were at the high-end of production and saw a quarterly increase of 27% to 18,306 NRI barrels of oil equivalent per day or 23,152 barrels of oil equivalent on a working interest basis. You can truly see how we have grown when you compare first quarter production this year with first quarter production last year, we are up 127%. We generated $47.8 million in adjusted EBITDA, which was only $2 million lower than Q4, despite lower sales due to lifting timing and lower realized pricing. We also generated $42 million in cash from operations, which allowed us to fund $27.7 million in CapEx and still grow our cash balance at quarter-end to 52.1 million with no debt. We also paid our quarterly dividend in Q1, which was increased by 92% and continued to repurchase common stock through our buyback program. We have positive momentum as we enter the second quarter of 2023, both operationally and financially, and we are building size and scale to substantially grow VAALCO. With our diversified portfolio of assets across four…

Thank you, George, and good morning, everyone. Let me begin by echoing George's comments about our continued strong performance. And as we look to 2023 and beyond, we are better positioned today to execute on our strategy, while adding and returning value to our shareholders. In the first quarter of this year, we generated adjusted EBITDAX of $47.8 million. This was slightly less than the 49.8 million in the fourth quarter of 2022, but up 43% from the 33.5 million in the first quarter of 2022. We benefited from a full quarter of production from Egypt and Canada, and had essentially no impact from derivatives compared with a large loss in the first quarter of 2022. Revenue declined from the fourth quarter due to lower sales volumes related to the delayed lifting and lower realized pricing. We reported net income of $3.5 million or $0.03 per diluted share in the first quarter of 2023, compared with $17.8 million or $0.17 per share in the fourth quarter of 2022. This decline in earnings was mainly due to lower sales volumes and realized oil pricing. Higher income taxes, increased interest expense, mainly due to the FSO lease and increased other income expense costs. Other income expense net during the fourth quarter of 2022, we recorded a $10.8 million bargain purchase gain that was partially offset by $7 million of transaction costs. During the first quarter of 2023, we recorded a transition period adjustment related to the acquisition that reduced the original bargain purchase gain by $1.4 million. In regard to the higher effective tax rate during the first quarter of each year, we project out our tax position for the full-year based on certain assumptions and then monitor it for the balance of the year. We are forecasting that our Gabonese tax…

Thanks, Ron. As you've heard this morning, 2023 is off to a strong start. We were able to generate strong adjusted EBITDAX, while funding all of our CapEx, quarterly dividends and share buybacks with cash flow and cash-on-hand and grew our cash position at the end of the first quarter to $52.1 million. We accomplished all of this with slightly lower sales and realized commodity pricing, which shows our continued efforts towards capturing synergies and increasing margins have begun to positively impact 2023 results already. We continue to expect additional cost savings being captured in 2023, and we are projecting increased quarterly sales in Q2. Additionally, we have remained focused on returning value to our shareholders. In Q1 2023, we nearly doubled the quarterly dividend and announced the Q2 dividend payment, which remains at $6.25 per share level. We also continued to repurchase common shares through the buyback program approved in 2022. Through the first seven months of the program, we have returned approximately 10.5 million to shareholders and return repurchased 2.2 million common shares through buybacks. We are delivering on what we committed to the market and to our shareholders, and we are in a solid financial position with no debt and a growing cash balance. Our strategy remains unchanged, operate efficiently, invest prudently, increase, and return value to our shareholders, maximize our asset base, and look for accretive opportunities. In the first quarter, you saw our capital spend ramped down significantly as we have finished the drilling and facilities projects in Gabon, and we are focused on drilling in Egypt and Canada in 2023. The lower capital spend profile should allow us to build meaningful cash throughout the year. But as we mentioned last quarter, our forecasted CapEx range of $70 million to $90 million is heavily weighted…

We will now begin the question-and-answer session. [Operator Instructions] The first question is from John White of Roth Capital. Please go ahead.

Yes. Good morning. My question was about the split on CapEx – drilling and completion CapEx between your three regions and Mr. Bain covered that in his remarks. So, I'll pass it back to the operator and say congratulations on the quarter.

Thanks, John.

The next question is from Stephane Foucaud from Auctus Advisors. Please go ahead.

Good morning, guys. Congratulations as well. A few questions for me and thanks for taking my questions. The first one is on Egypt and again the receivable. And I'm trying to see whether I'm comparing apple with apple. So, at the end of December, we had 140 million total receivable. And I think 100 million of that was Egypt, including the receivable. At the end of Q1, it seems we have about [100 million] [ph] total. And you're saying 50 million are receivable for Egypt, that would suggest you got 50 million payments of receivable in Q1, which is the case is fantastic. That will be my first question. And my second question is, could you talk about the difference in economics between vertical and horizontal well in Egypt in terms of cost, IP rate and recovery? Thank you.

Okay. Thanks for that, Stephane. It's Ron here. I'll take the first part of that question on liquidity around receivables and Egypt, if I understand your question correctly. I think the first thing to bear in mind is, in Q1, we actually had a cargo that we got 450,000 barrels listed and obviously taken out of country and paid offshore. That was $28.5 million worth of receivables, which is great because, obviously, there's no EGPC involved there. We're dealing with a trader. With regards to the receivables for EGPC, generally, obviously, we heard some of the issues that other companies are having, but we certainly did not see it through Q1. Our cash collections and offsets in Q1 were about $19.5 million, Stephane. And we sold directly through domestic sales or January sales of about $11.5 million. So, we actually had a reduction in our receivable from year-end through to Q1. We ended up in Q1 with about $26.5 million worth of receivables in trade AR and then, of course, we still got the $51 million receivable, which is the – backdated entitlement barrels that we continue to have discussions with EGPC and the ministry on to realize cargo's based on that. That's probably giving you some color to Q1 and the liquidity there. With regards to the capital components, George can jump in on this one. But the vertical wells themselves are – obviously, just for our guys, especially our old VAALCO guys who are used to seeing wells being drilled offshore at $25 million, $35 million. A vertical well in Egypt is typically under $1 million or around about $1 million. We have seen some, obviously, increases in costs over the last six months, just again due to the supply chain issues that you see globally and the fact that there's not that many service providers actually operating in Egypt. The Arta well that was drilled at the beginning of Q1, that was our long lateral, the first time that we've drilled a long lateral well in Egypt. And that well is probably coming in about $3 million, $3.5 million. So that's a differentiation between the well costs. These wells are very economic, although you may see discussions about 100 barrels 200 barrels of oil per day coming out of these wells. Because of such low cost, we're looking at internal rates of return well above 100%. So again, we're quite happy to continue to invest in Egypt at those economic criteria as long as we continue to crystallize on the cash position. The only negative part for Q2 going forward is that we don't have a lifting in Q2 and export listing in Q2, but we are building up our inventory. We will have enough inventory as we exit Q2 to push for a Q3 cargo.

Thank you. And with regards to...

I'll just add on – on two points, particularly within the drilling campaign in Egypt, as I mentioned earlier in the call, we've seen significant improvements in the production numbers in Egypt. We've seen considerable success in the drilling campaign, not just from the vertical wells. Obviously, the complexity in the first Nukhul Arta well, Arta-77, it's – that particular well is currently producing around to 200 barrels a day and is still cleanup. So, we expect it to continue that cleanup over the next few months. But we also – because of the length of the lateral, we expect a very low decline rate on that well. So, that well is difficult to – it's still a very economic well, but it was a well just due to the well of the lateral, it took some time to drill and complete. When we look at the cycle times now that we're achieving in Egypt from the traditional or the historic position between drill and complete, I mean we are really pushing the efficiencies to the maximum on that drilling campaign. So, even though the costs are relatively low, it's 1 million, 1.5 million per well, we're actually driving those costs more because we're basically managing to drilling complete about 1.5 wells every month. So, we're very, very quickly getting to getting through that drilling program and comfortably staying within the CapEx, we currently do all the CapEx gains in Q2.

Great. Thank you.

The next question is from Charlie Sharp of Canaccord. Please go ahead.

Yes, thank you very much and good morning gentlemen. I appreciate the thoughts update for the Q1 numbers and operations. I just wonder if you can highlight high level, the next – let's say, over the next six months, the key internal and external point in terms of Equatorial Guinea and Gabon that you need to sort of bed in before a return to capital expenditure rising again next year? Thank you.

I partly missed that question, Charlie. Was that for Equatorial Guinea and Gabon, the key points?

Yes. Just the sort of high-level key points that you need to get in place internally and externally before you know exactly what next year will look like in [indiscernible]?

Okay. So, let me start with Gabon. Obviously, from the drilling campaign last year, we had a mixed bag of results. We had some very strong performance in the first two wells in the Gamba sands. And then on this – on the latter two wells, we didn't find the Gamba sands on the third well and had a success on the Dentale exploration leg from a reference standpoint. And then obviously, from the fourth well, it didn't pan out as we had modeled for the Dentale well there. So, we are taking and we have taken all these geological data points in addition to the new seismic analysis that was acquired in 2020 and interpreted in 2021. To look at the opportunities for the drilling campaign in Etame where we reduced the overall risk of the campaign for either additional Gamba targets for accelerants, but also looking at step-out opportunities and what the risk factors are around step opportunities to continue to fill the [indiscernible]. So, for the last six months or so and continuing for the next few months, one of the key analysis is going to be the subsurface analysis and mapping around the Etame field, the reason [indiscernible] as well is key for us to understand the geological place and where we put the campaign together for 2024, 2025 we are looking at the lower risk prospects to increase the production and increase the drilling success. So that's really the key focus in the Gabon right now is a deep dive into the subsurface structure and the risk profile. With regard to Equatorial Guinea, as I mentioned earlier on the call, we've got to get to a point of finalizing the documentation with the partners. Once we do anticipate that to be completed by the summer, and I also mentioned on the call, we brought about six or seven detailed studies that are kicking off on completion of that documentation, which will move into free production CapEx – and that's one of the – so the external element that you mentioned would be the finalization of the documents and sitting down and agreeing with our partners in the upcoming TCM meetings. And the internal side is with that work schedule going through optimizing the top side analysis within the program for venous looking at the, as I mention, the effectiveness of doing a dedicated campaign of three wells rather than moving the rig in and out and the economic efficiencies that come with that. And the practical piece of work that we'll be doing this year is obviously conducting a seabed survey around the shelf area for the location of top side facility.

That’s great. Thank you.

The next question is from Jeff Robertson of Water Tower Research. Please go ahead.

George, on Slide 5 of the deck, you showed the benefits that you all have seen in production in Egypt from optimization efforts. Can you talk about how much more heavy lifting there is to do just trying to improve field operations and what that could mean for production?

Yes. I mean we've done a considerable amount of work in a very short period of time, as I mentioned, about reducing the back pressure and eliminating the blockages that were in the production facilities in Egypt. We've got – and we will be putting together a presentation for EGPC and the Ministry to show before and after scenario, both on the field locations and in the production locations. So, when I look at the heavy lift on production optimization, I think, and I know stores in the room beside [Ron] [ph]. But my view is, I think we've done a lot of the heavy lifting in relation to production optimization, and we're reaping the benefits of that. And as I mentioned, we're really focused right now on the drilling optimization. So, we're reducing our drilling plans. But one of the other items we're looking at is that workover in the South, [has a lot well] [ph] to see if we can bring that well back on production, which regard a few hundred barrels per day to the field. The other key elements there that we've been working on, as I mentioned earlier, is feeling that we improve the CSG position inside the field of preventing and for the reducing the opportunity for uncontained spills. That's been a big program with us going through the field operations in the first quarter and into the second quarter. I think we still have more to do there. But I'll pass over to Ron, if he wants to add any color to that operation.

Yes. Thanks, George. Yes, I think, I mean, we've put – we've sort of set the stage for a lot of the big projects. I think that will impact us and provide, I guess, positive results going forward. There is still a large, I guess, inventory of smaller items that we're looking at, specifically around downtime, pipeline integrity, facility integrity, emissions, electrification and crude oil polishing that we think we can make a significant impact on going forward. But I think you've covered most of the other ones off.

In Canada, I think you all talked about improving operating efficiency as well, including pad designs and facilities. Will the outcome of that work have an impact on how you think about a 2024 capital program?

Well, most definitely. I'll let Ron jump in in a minute. But we have always said that we need to try and ensure that we reduce our time lines between drilling and complete and we need to figure out within the existing environmental conditions that happen in Canada. So, how do we drill and complete in the same cycle and now have wells basically suspended for months on end. I think what we've seen in Q1 and coming into Q2 is a significant improvement in those cycle times. As mentioned earlier on the call, we've seen the two wells that were delayed from 2020 to come online in Q1. And we've seen another two wells coming online in Q2 to the point where we've got production on a BOE basis in Canada well above 3,000 barrels a day at the moment. So almost, if not a record production level for that operation. So, we are driving those efficiencies. We are reducing those cycle times, and we are starting to see the dividends both in Canada and in Egypt with the increased production. So, when we look at our guidance position in Q1 and the production levels that we've actually achieved, we're right up there where we would plan to be. Anything you want to add to that, Ron?

Yes. I mean, I think the key to Canada is, as you mentioned already, George, cycle times. Canada is unique in a sense that you have access to a lot of the technology and the infrastructure, and it's being able to, I guess, engage those services and the technology and time. What causes the long cycle times is predominantly surrounding the weather. So, these are your breakup periods in the spring and in the fall. And it's building a program that, I guess, fits into that weather window that allows you those faster cycle times. From a drilling perspective, the Canadian oilfield is an experienced segment when it comes to drilling the horizontals, so long horizontals. And again, our focus needs to be on drilling long laterals, not short laterals. So, we're looking at the 3-mile laterals versus 1.5-mile laterals – and then the other thing is doing pre-facility work ahead of the drilling campaign so that when it comes time to tie in, you've already got the pipelines in place and you've already got the facilities geared up to do that. So, it's a combination of those things that will make Canada is successful.

Thank you.

We have time for questions from one more person. Next question comes from Bill Dezellem of Tieton Capital. Please go ahead.

Thank you. That’s Tieton Capital. Let me start with the timing of the lifting. I need a little clarification because I was thinking that the move to the FSO tele that, that was going to give you a lot more consistent liftings. What am I missing or what was different in this quarter?

George, I could take that one if you want.

Yes. No, go ahead. That's fine.

Yes. So generally, we target our liftings to be roughly every 4 to 5 weeks. And in the winter months, particularly in the Gabon segment of West Africa, you see a lot of heavy currents that impact, I guess, the ability for vessels to more adjacent to the tanker safely. And we had a lifting scheduled for late March. I think it was around 26th, 27th of March. And basically for five or six consecutive days due to the heavy currents, we were unable to actually hook-up the tanker and proceed with that lifting. So, what happened is that lifting got moved into early April, I think, April 3. So it was delayed by about six days, but it did miss the first quarter cutoff. The FSO has the ability contrary to what we previously had with the FPSO is to continue producing into the FSO, due to the additional cargo volume that we have now. So, normally, in the past, we would have had to probably shut-in because we would have been at tank tops because of the lifting had been delayed. What happens now is that because of the additional cargo volume, we can continue producing and then the sale or the movement of the cargo, if it's delayed a couple of days, it's delayed, but it doesn't impact our production.

Sure. That's really helpful. So, it was also my impression that the FSO was positioned in such a way to minimize the impact of the weather. So, is the implication that the currents were really, really strong or did you find that, that positioning maybe wasn't exactly what you originally hoped for?

Well, I guess the positioning of the FSO as with any vessel is a judgment call between trying to mitigate, I guess, the currents for most of the time. So, we know that January, February, March are generally times of the year when there's a massive current swing in Gabon. Starting in, sort of April, that current swing goes 180 degrees the other way. So, it's trying to come up with a location and a mooring location that sort of gives you the best odds for the most liftings on time. So, for instance, we had another lifting that was scheduled to start a couple of days ago. It started on time. It's underway. No issues with currents. So, it's really do you set your lifting up so you can only do those three guaranteed – or do you set it up so that your vessel can handle most of the liftings most of the time.

So, really well prepared for 9 out of 12 months and the other 3 is just going to be a little more on mother nature.

Exactly. And with the additional capacity we have now in the FSO, it doesn't actually impact our production, just impacts the sales from quarter-to-quarter if it's a quarter end lifting.

Great. Well, that's really helpful. And then would you discuss the field gas line work that's being done an Etame? I didn't fully understand what was actually being done and ultimately, the end goal of that project?

Sure. So, there's a low-pressure fuel gas line that runs from the SEENT platform to the Etame platform supplying fuel gas, to the Etame platform, power generation and process. And that also supplies gas from Etame to the new FSO for boiler service. We, during one of our routine inspections picked up a flange leak or what we've now identified as a flange leak. It's a very small leak, but nevertheless, it is a small flange league adjacent to the SEENT platform. That will require diver intervention. So, at this point, we're essentially scoping out the [boats] [ph] that are in the area and when those boats are available because we're obviously trying to tie that in with some additional work with some of the other operators to mitigate the cost of that. The impact of not having fuel gas essentially means that the tele or the FSO is burning liquid fuel in the boilers, and that's the additional cost that we're seeing.

That's helpful. Thank you. And then one final question, if I may. If I recall correctly, you all were looking at a potential adjacent field to Etame with – in conjunction with a new partner to develop. What is the update on that?

I guess on that one, Bill, we actually did have some good discussions with the Gabonese government in Q1. The data, it is in conjunction with our partners, which are BWE and Panoro. We were hopeful of – because this has been going on now for some 12, 15 months. But we are hopeful that a conclusion is arriving relatively soon, certainly hopeful in the next few months. It is key to say that there has been more progression in this last six weeks period to do with block G&A, and we are very encouraged with the adjacent block to Etame than there has been in the previous six or seven months. So, hopefully, we'll see some more movement the next time we report it.

So George, the issue is with the Gabonese government as opposed to amongst the partners?

I've met with the partners directly – one of them directly who – there's no issues between the partners and the issues directly with the DTH and the Gabonese government.

Great. Thank you both.

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

Thank you very much, operator. Well, I can say that we got back on track for Q1, we've had a very strong performance in the production side in Q1. We've seen some sensitivity around commodity pricing, however, we've maintained [Technical Difficulty] that we made to the market with regard to buyback and regard to dividend because the commodity prices have remained above the levels on which we made those commitments. The company's operating performance is strong, albeit that we have to acknowledge that, as Ron mentioned, the stock price performance has not been strong, and that's something we have to wrestle with and something we have to look at when we're looking at how we are conducting our share buyback program. At the moment, we remain restricted in our blackout period, but it is something that we will be addressing and how we accurately adjust these levers to maximize the opportunity for repurchase on the undervalued stock position. As always, I say this at the end of every call, anyone that we haven't got to who was in the queue, and I fortunately can't see the queue today, but anyone we haven't got to or anyone who wants to reach out and have a discussion, please contact [our Chris] [ph] directly, and we'll make sure that, that can be arranged for you. In the meantime, thank you very much for your time taken and listening to the call today.

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