VAALCO Energy Inc
NYSE:EGY
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VAALCO Energy Inc
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Ladies and gentlemen, thank you for standing by, and welcome to the VAALCO Energy's Third Quarter 2024 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, and welcome to VAALCO Energy's Third Quarter 2024 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the third quarter. 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 limit your questions to one and a follow-up. You can always reenter the queue with additional questions. I 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. 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 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 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 third quarter 2024 earnings conference call. For the past 2 years, we have met or exceeded our quarterly production guidance, leading to consistently strong operational and financial results, including net income, adjusted EBITDAX, and cash flow generation.
Maintaining operational excellence and consistent production across our portfolio is essential to expanding adjusted EBITDAX, which will enable us to fund organic growth initiatives and position us as a larger player in the industry. We are executing at a high level and continue to deliver results in line with or above our guidance. In the third quarter, we experienced quarterly results that fully incorporated the Svenska acquisition, which occurred at the end of April.
For Q3, we increased our adjusted EBITDAX to $92.8 million and through the first 9 months of 2024 have delivered $227 million of adjusted EBITDAX. We sustained our commitment to returning cash to shareholders in Q3 2024 through our regular quarterly dividend and have also announced the dividend for Q4.
I would now like to go through and give a quick update on our diverse portfolio of high-quality assets, beginning with our newest asset in Cote d'Ivoire. We swiftly and efficiently completed the Svenska acquisition in April 2024, securing a valuable asset with reserves surpassing our initial expectations, all at a highly attractive price.
Based on the results of our third-party reserves engineers, we have SEC net proved reserves as of year-end 2023 of 16.9 million barrels of oil equivalent with 93% being oil. Our previous 1P working interest CPR reserves were 13 million barrels of oil equivalent. This 30% increase in reserves further justifies the acquisition and improves the metrics associated with the purchase.
In Q3, we had 3 shared liftings in Cote d'Ivoire, driving our total VAALCO sales 20% higher overall versus Q2. The timing of the FPSO shutdown in sail away remains scheduled for Q1 with these plans now becoming more firm as we move closer to the shutdown targeted date. We are collaborating with our operator at Cote d'Ivoire, and we'll provide additional information on the Baobab FPSO project and future drilling plans when we issue our 2025 guidance in Q1.
Turning to Canada. We successfully drilled 4 wells in the first quarter of 2024, completed these wells in March and April and brought the wells online. As a reminder, we drilled longer laterals to improve the economics of the program and all 4 wells are 2.75-mile laterals. We are very pleased with the production results from our drilling program, and as you can see that in the production mix in Canada.
In Q1, our Canadian production was about 60% liquids and in Q2 and Q3, our Canadian production was approximately 75% liquids from new wells coming online with a lower GOR. This strong oil production has rebalanced production in Canada more in favor of liquids, which contributes to the strong production performance and our overall profitability. As the wells continue to produce, they are in line with our type curve, and we are optimistic about the future drilling potential in Canada.
As I mentioned in the last call, we are also currently drilling an exploration appraisal well in the southern acreage, for which we hope to have results prior to year-end. In our southern acreage, we have minimal horizontal subsurface information, and this exploration well, if successful, could prove up additional long lateral wells in the future with the potential to add proved undeveloped locations.
In Egypt, as we disclosed last quarter, our focus in 2024 has been on high rate of return capital workover projects to help mitigate decline. As you have seen in the earnings release, we had 3 recompletions in the third quarter. In addition to the successful workovers, I am proud of a major milestone that we accomplished in Egypt. We have gone over 2.9 million man hours without a lost time incident this year. This is a testament to our commitment to safety, training, and dedication of all of our people in the operation.
As I mentioned in the last call, we have a 10 to 15-well program. And in the fourth quarter, we have contracted the rig and will commence at least 2 of these wells this year. We expect to drill and complete at least a single well prior to year-end and complete the drilling of the second well. However, the second well is not expected to provide production until January 2025. We continue to engage with the Ministry and EGPC on the backdated receivables issue.
We are balancing our working capital position between a limited but necessary drilling program with the indications from EGPC of a program to address the backdated position. We also plan to fracture one of our wells in South Ghazwa and the Western Desert late in the fourth quarter. Results will be available in Q1 2025, and if encouraging, will have a positive impact on our development opportunities in this area for the future.
Moving to Gabon. Given that we haven't drilled a well in Gabon for over a year, we are pleased with the positive overall production results with strong production uptime and improved decline curves on the wells. The FSO and field reconfiguration projects in 2022 have allowed us to minimize downtime, capture efficiency, and reduce overall OpEx.
Currently, despite not initiating the planned drilling in 2024, our production guidance remains firm for the year, which is a testament to the quality of the Etame field and how the reservoir has positively responded to the reconfiguration.
Looking ahead to 2025, as I stated last quarter, we initiated a bidding process for the 2025 drilling program. We're almost complete on the bid evaluation and contractor selection. It is intended that we will announce results of this evaluation in the very near future. However, I can confirm that the timing of this project remains on schedule for mid-2025.
Since our last communication, we have continued to review the well sequencing of the program and the testing of the Ebouri shut-in wells. When finalized, this will provide greater analysis for the equipment selection required for the Ebouri wells and the timing of the wells within the program sequence.
The other planned wells, 2 infill wells within Etame, a gas well in SEENT, and an exploration well remain in the plan. This is in addition to the potential of a small workover program at Etame. We will provide more detail on CapEx and volumes when we present our 2025 budget and guidance. Our expected CapEx spend for 2024 on long lead items remains as previously noted, between $30 million and $40 million.
Regarding blocks G&H recently, the government of Gabon signed these PSCs for exploration blocks, which they requested to be renamed Niosi Marin and Guduma Marin. This follows the technical provisional award announced in October 2021, granting VAALCO a 37.5% nonoperating working interest with BW Energy as operator, also holding a 37.5% working interest, and Panoro Energy as a nonoperating joint owner with a 25% working interest.
Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited to begin working with our partners to begin examining the possibilities for these blocks.
In Equatorial Guinea in March 2024, we announced the finalization of the documents related to the Venus Block P plan of development. This summer, we began our front-end engineering design or FEED study. We anticipate the completion of the FEED study will lead to an economic final investment decision or FID, which will enable the development of Venus. We are very excited to proceed with our plans to develop, operate, and begin producing from the discovery in Block P offshore Equatorial Guinea over the next few years. We look forward to discussing this new area of operations in more detail once the FEED study is complete.
Throughout 2024, we have delivered on or exceeded our guidance operationally and our solid financial results continue to outpace analyst expectations. We remain focused on growing production, reserves, and value for our shareholders. I would like to thank our hard-working team who continue to operate and execute our plans.
Over the past 2 years, we have significantly diversified our portfolio, enhancing our capacity to generate operational cash flow and adjusted EBITDAX, return capital to shareholders, grow our cash reserves while maintaining a bank debt-free position. We are well-positioned to execute the project in our enhanced portfolio and our proven track record of success these past 2 years should instill confidence for our future.
With that, I would like to turn the call over to Ron to share our financial results.
Thank you, George. And once again, good morning. I will provide some insight into the drivers for our financial results with a focus on the key points.
Let me begin by echoing George's comments about our continued success through the first 3 quarters of 2024, driven by our strong operational performance.
In the third quarter, we saw the positive impact from the Svenska acquisition, including 3 [ shade ] liftings in Cote d'Ivoire. We generated $11 million in net income or $0.10 per share and $92.8 million in adjusted EBITDAX. Through the third quarter of 2024, we have now generated $227 million in adjusted EBITDAX, which is over $40 million more than we generated in the first 9 months of 2023.
Let's turn to production and sales, which along with realized pricing drives our revenue. As George mentioned, we have met or exceeded production guidance for the past 2 years, with production and sales up in the third quarter, driven by a full quarter of results from Cote d'Ivoire. We completed 3 liftings in Cote d'Ivoire in Q3, driving our sales growth. Total NRI sales for the quarter increased to 23,198 barrels of oil equivalent per day at the high end of our guidance with NRI production of 21,416 barrels of oil equivalent per day, the midpoint of guidance.
I'd like to reiterate that with a diversified portfolio of assets, we will have changes from quarter-to-quarter in the mix of sales from each of our producing areas. This change in mix impacts our realized pricing and ultimately our revenue and earnings. But if you look at the bigger picture and over a full year, you'll see impressive growth across our expanding portfolio of producing assets. Pricing remained stable in Q3, and our hedging program has always looked to help mitigate risk and protect our commitment to shareholder return. Our current hedge positions were disclosed in the earnings release.
Turning to costs. Our production costs for the third quarter of 2024 were at the low end of guidance, both on an absolute basis, on a per barrel basis. Absolute expense was $42.3 million and on a per barrel basis was $19.80. I want to remind you that the 33% decrease compared to Q2 was driven by the fact that Q2 included a $15 million noncash purchase price adjustment in Cote d'Ivoire for the inventory that was purchased. Our focus remains on capturing synergies and keeping our costs low to enable us to maximize margins and increase our cash flow.
G&A costs were also in line with guidance, and they fell quarter-over-quarter. We completed our back-office process improvement project with the implementation of a single cloud-based ERP across the whole company and went live in Q3 2024. This should allow us to streamline processes and efficiently work across our multiple geographies located around the world. The project was completed on time and on budget and is a testament to the effort and dedication of the entire team.
Non-cash DD&A costs increased quarter-over-quarter, primarily due to increased depletion costs associated with the addition of Cote d'Ivoire. Valuation of Cote d'Ivoire is comprised primarily on the proven, developed, and producing reserves, which assumed an estimated disconnection schedule occurring in Q1 2025 in the CPR, thereby depletion expense is accelerated due to the higher liftings than forecast in the reserve report.
Moving to taxes. And as I've previously stated, in Gabon, our foreign income taxes are settled by the government through in-kind oil liftings. In Q2, we accrued $30.2 million in foreign income taxes for Gabon through the government taking our oil barrels as payment in kind. We forecast that GOC will lift their entitled barrels early in Q1 2025, and there will be no further Gabon state list this calendar year.
Third quarter tax was impacted by nondeductible items such as the Svenska transaction costs and the change in market value of tax barrels due to Gabon state mark-to-market at quarter end. Tax costs in the second quarter of about $32.6 million resulted in an effective tax rate of about 75% in the quarter, impacted by nonrecurring discrete items. This is higher than prior quarters, but offset by the 25% effective rate in Q2. As you can see, over the long-term, excluding discrete items, our guided effective tax range of 55% to 60% is a good forecast.
Turning now to the balance sheet and cash flow statement. Unrestricted cash at the end of the third quarter grew to $89.1 million, driven by strong sales. In Q3, we spent $12.4 million in cash CapEx and returned $6.5 million through dividends to our shareholders. I'd like to point out that there is some noise in the cash flow statement regarding the Svenska acquisition. We have a slide in the supplemental deck showing a waterfall to help to explain the movements.
On the investing activities, you will see $40.6 million in cash received in business combination. This was cash that Svenska had on the books to be seller accrued liabilities that flowed through the operating activities section that VAALCO assumed with the purchase.
Last call, we discussed likely working capital movements, primarily related to Egypt. In the third quarter of 2024, we sold all Egyptian production domestically, which drove our September accounts receivable higher. In early July, an USD 8 million cash payment of Egyptian receivables was received.
Further to that, we also received $5 million worth in equivalent Egyptian pounds in August and in September versus $10.6 million in the whole of the preceding several months. We continue to utilize offsets and collectively, the payments plus the offsets amounted to approximately $29 million for the quarter.
Additionally, EGPC has now provided written confirmation and recognized our invoice in the June payables related to the contractual backdated receivable from the merger of the PSCs of approximately $40 million. This is a major step forward and with EGPC demonstrating through March and July back payments to IOCs and with the new oil minister prioritizing resolving the age table situation, we are pleased to continue to work with the Egyptian government, which has made a concerted effort to reduce its backdated build payables in 2024.
As has been the case since the third quarter of 2018, we are carrying no bank debt and have credit facilities available to continue to build value. In Q3 2024, VAALCO paid a quarterly cash dividend of $0.0625 per common share or $6.5 million. In 2024, we've now returned over $25 million in shareholder return. We also announced the fourth dividend payment of the year, which will be paid in December.
Let me now turn to guidance, where I will give you some key highlights and updates. Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with the production breakout of both working interest and net revenue interest by asset area. For the total company, we are forecasting Q4 2024 production to be between 23,800 and 26,700 working interest barrels of oil equivalent per day and between 19,400 and 22,000 NRI barrels of oil equivalent per day. This is down only slightly compared to the third quarter due to natural decline.
For the full year 2024, we are tightening the range and now forecasting our total company production to be between 24,100 and 25,400 working interest barrels of oil equivalent per day and between 19,300 and 20,600 NRI barrels of oil equivalent per day. Looking at production by asset for the full year, we are expecting natural decline in Gabon and Egypt, although the capital workover program in Egypt has helped to mitigate some decline.
In Canada, we are seeing year-over-year growth from our drilling campaign and Cote d'Ivoire, we are reflecting operations from May through December in our full year numbers. For the fourth quarter, we are forecasting our sales will be more or less in line with our production, but down compared to Q3 due to less offshore liftings.
We expect our absolute operating costs to be only slightly higher compared to Q3. But because we're expecting fewer liftings, we are projecting our per barrel of oil equivalent range to increase slightly with a range between $17.50 and $22.50 per barrel of oil equivalent. We are also expecting flat to slightly lower absolute G&A.
Finally, looking at CapEx, our 2024 capital spend is between $110 million and $130 million as we prepare for the 2025 FPSO change out in Cote d'Ivoire, the anticipated next drilling campaign in Gabon and some drilling in Egypt and Canada that could impact 2025 Q1 production.
For the fourth quarter, we are expecting a range of between $40 million and $60 million for our CapEx, which includes a fifth well drilled in the southern acreage of our Canadian asset and FPSO marine disconnection and long lead item contracts.
In closing, we are executing our strategy and adding meaningful value. With the Svenska acquisition, we've delivered a meaningful increase in production and sales, which has also increased our ability to generate additional adjusted EBITDAX and operational cash flow. We are well positioned to execute and fund a robust organic capital program across our diversified assets over the next several years.
With that, I'll now turn the call back over to George.
Thanks, Ron. We will continue to execute our strategy focused on operating efficiently, investing prudently, maximizing our asset base, and looking for accretive opportunities.
As you have heard this morning, the first 9 months of 2024 has been very profitable. We have generated $46.8 million or $0.45 per share in net income and almost $227 million in adjusted EBITDAX.
With the closing of the Svenska acquisition at the end of April, we have seen a positive impact to production, sales, OpEx per BOE, operational cash flow, and adjusted EBITDAX. Looking across our asset base, we are pleased with the Canadian drilling results. We are planning the drilling campaign at Etame, working with the operator in Cote d'Ivoire on the FPSO refurbishment and development drilling program in 2025 and 2026.
We are progressing the FEED study in Equatorial Guinea and optimizing production while executing a capital and expense drilling project in Egypt. Our entire organization is actively working to deliver sustainable growth and strong results. I believe we have gained credibility over the past 2 years having delivered on our commitments to the market and to our shareholders, and we will continue to deliver with the exciting slate of projects, we have over the next few years.
We're in an enviable financial position with no bank debt and an even stronger portfolio of producing assets with future upside potential. In addition to funding our capital programs, we have remained focused on returning value to our shareholders. In Q3 2024, we returned over $6 million to our shareholders through dividends. We are on pace to deliver another $0.25 per share annual dividend for 2024, what we paid out in 2023 with our current share price is a yield of around 4%.
We will continue to finalize our projects and timing for 2025 and report guidance and expectations in the first quarter of 2025. We're truly excited about the future and VAALCO now has multiple producing areas and future prospects that have diversified our risk profile and our sources of income. We are confident in our ability to execute on the many projects ahead, largely because we have been highly successful over the past 2 years developing and growing our assets. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserve, and cash flow has led to outstanding results thus far, and we believe that we will carry that momentum into 2025 and beyond.
Thank you. And with that, operator, we are ready to take questions.
[Operator Instructions] And our first question here will come from Jeff Robertson with Water Tower Research.
George, in Gabon, where do you see the natural production decline going in 2025 since it's been, I guess, a couple -- 1.5 years since your last well completion?
Thank you for that, Jeff. I mean I think as we pointed out in the call earlier today, we've actually seen some terrific improvements in reservoir performance and a big reduction in decline for a couple of reasons. One reason is obviously with the reconfiguration, we've considerably reduced the back pressure on the field, and we've seen improved reservoir performance from that position. And the second, again, as a result of the reconfiguration, we've seen hugely reduced downtime down to 3% for planned preventative maintenance. So when we look into 2025, as I mentioned, we're due to start the campaign around about May or June '25, and that's mainly due to rig availability. That's the earliest that the rig would be available for us. I still see the decline probably hitting between 7% and 9%. We do have some planned maintenance in Q1, which we'll do ahead of the drilling campaign. But I still think what we're seeing from the performance of the reservoir is particularly encouraging.
Does -- will reducing the back pressure and the performance gained from that have an impact on how you book reserves there?
That's something we're looking at. Actually, I'm having a meeting on that next week. That's something we are considering to look at with the performance of the reservoir, particularly through 2023 and 2024, are we underestimating the size of the tank? Or are we underestimating the recovery factor. So that's a piece of work that we will have completed in time for the CPR report will be issued in January.
And then if I can squeeze one more in. Lastly, on the drilling campaign, if you start in the -- sometime late in the second quarter, I guess, based on how you sequence the wells, would you anticipate having some production contribution from that program in the back half of 2025 or would it more be weighted to 2026?
No, no. We'll definitely start with production wells. The key debate we're having right now is whether we can start on the Ebouri side of the campaign or whether we're starting on the Etame side of the campaign. And that's really down to the continued testing and evaluation, particularly around Ebouri 4H for the H2S concentration and what types of materials we need in order for those completions and also the sidetrack -- sorry, the step infill wells in Etame. Now when it comes to the Etame infill wells, I think we're good to go on those all day long. The kit will be ready on time. So it's really just a question between how many rig moves do we want to take into the program between the infill wells at Etame and the opportunity to rehabilitate, restart the Brewery. But it definitely will be production wells at the front of the sequence.
And our next question will come from Chris Wheaton with Stifel.
Question, George, to you first on Cote d'Ivoire. When do you think we can expect a little bit more clarity on what the timing and likely spend is going to be around both the FPSO restart whenever that's happened, which I see from recent presentation on your website, it looks like it's going to be sometime 4Q next year. And then obviously, an ongoing drilling campaign, which is going to be spending money, hopefully generating good returns doing that. So I wonder when you could talk about when we're likely to get that timing because that seems to be the sort of probably the biggest swing factors in terms of your likely reported performance in calendar '25?
Yes and no. I mean, I think we've confirmed already that we don't see any change in the sail away time for the FPSO. So we've confirmed in discussions with the operator that the Q1 disconnection and sail away is still what will happen with the FPSO. The contracting basis for that to go to dry dock and the disconnection and the contracts around that are all being placed as we speak. When we look at some of the capital spend you've seen come through this year, it relates not only to the MV10 reconfiguration, but it also relates to the '25, '26 or probably '26 is more fair date drilling campaign. So we're already spending CapEx on that right now.
When we get to look at the total overall project and the project time lines, I would expect to be in a position late this year or early next year to be able to give a detailed project breakdown with time lines and costings. Obviously, we have internal costings right now. One thing I'll say with a great degree of confidence to everyone right now is we are more than adequately funded to carry out the campaigns that we've already indicated to the market, which includes Egypt and Gabon and Cote d'Ivoire. So there's no issue around being able to fund these campaigns. It's all about the timing. We haven't had confirmed timing and project schedules as yet from the operator. But as soon as we have those, and we do not expect those to deviate significantly from the estimates we're currently carrying, we will certainly make an announcement around that. But it certainly will be no later than early Q1 next year.
Two questions for Ron, if I may. Firstly, working capital. Interestingly, every quarter this year has been -- seen a working capital outflow, which is quite unusual, even if you back out the $15 million of Cote d'Ivoire receivables build, you still had working capital outflow this quarter. Is there sign that's reversing in 4Q? Because obviously, that's been quite a drag on your free cash flow generation so far this year. And then a question on depreciation. Forgive me, I didn't quite understand the answer or the commentary you gave on the higher DD&A because I would have thought Cote d'Ivoire is lower unit DD&A than your average. And therefore, if you've got more Cote d'Ivoire barrels, you should have lower unit DD&A, but unit DD&A was up sequentially. So I was trying to sort of -- that didn't seem logical to me. Could you perhaps explain why I'm going wrong there?
No problem, Chris. Let me handle that. First of all, on the working capital, I think what you've got -- you're right in removing that CDI receivable, which was paid in early October. During the year, there's been a number of things. As you know, we've been out of the drilling campaign really Canada, we had the 4-well campaign in the first quarter. Since then, obviously, our AP and our CapEx accruals have reduced considerably, and they will ramp up again in 2025 when we go into the next campaigns. Outside of that, we've got our reduction receivables. That has trended up this year. I think year-to-date, we're up about $19 million since December. It's trending about $6 million/$7 million per quarter, the differentiation between what we're selling at present pricing and what we're collecting and/or using as offsets.
Obviously, with Ivory Coast coming in too, we've got a little bit more oil in the tank with 2 FPSOs as well. So our inventory is a little bit higher. And then in Q2, you had some one-off events that we talked about. We were DMO annual payment in Gabon, which is cost recoverable. We'll have our DMO discount against the pricing in CDI in Q4. So you do have these one-off events that do swing things too. So nothing more than that, Chris. It does look strange, but you will note as well in our cash flow, and we did talk about the working capital noise with the waterfall chart that we got cash with the Svenska business, and we had to settle a number of liabilities that were seller-led liabilities that we settled post year-end too. So all of those factors are driving the working capital outflows in each of those quarters.
Moving on to DD&A. It's quite simple, Chris, on this one. Although the operating cost per barrel is lower in Ivory Coast in some areas. When we valued the acquisition, when we put together the purchase price around that $40 million that we paid for it, obviously, a large proportion -- the predominant proportion of that valuation goes into the proven developed producing reserves. And those proven developed producing reserves are actually only going through until it comes off station, other words, when the disconnect happens, which was obviously targeted for Q1 2025.
So you've got that situation, where you've got a large portion of the valuation being effectively amortized and depreciated through until January 2025. Now I do think as we go through Q4, there will be a truth up on the PDP as we go into 2025 because essentially, we'll have most of our PDP amortized and gone before the end of the year. But that's why the DD&A component is so high and made exacerbated by the fact that we have 3 listings in Q3 versus 1 listed in Q2 for CDI.
That last answer is very helpful, Ron, because I was using the 2P reserves, not PDP reserves as the denominator in that unit DD&A equation. So that explains why those numbers don't matter.
And our next question will come from Charlie Sharp with Canaccord.
Just really wanted to return, if I may, to Gabon and the drilling program. And I think you indicated that that may start sort of mid-Q2. It has slid a little bit. I think you also indicated that that was rig related. I just wanted to chase up whether that is because the rigs just aren't available locally or is that pressure on rig rates? And can you give us sort of ballpark figure of what each of the wells would cost to drill? And then the final bit of that is of the 7-well drilling program, I think you've indicated that some of those are workover wells. How many actual new wells will there be in that 7-well program?
Okay. Let me take each section. So there's no pressure or no issue around rig rates. When we put the LOIs and tenders out there -- sorry, when we put the tenders out, we had somewhere around 7 bidders. And obviously, we were looking at a mixture of the bareboat rate versus mobilization versus the geographic location of the unit that was being bid. Taking all that into account, we are currently in negotiations over a certain unit that is -- has the lowest mobilization opportunity.
And with that, it's already executing a program in West Africa. It completes with one company in February, then it's to -- it's got 2 other wells to do in another part of West Africa, then it will come to us. So is purely one of economics as opposed to any kind of pressure on rates, et cetera, economics and expediency and it's a rig that is not stacked, it's hot working and one we've used in the past. So that is really the timing is down to the schedule that the rig already has committed to as opposed to any other external factor.
When we look at the program itself, it's -- I haven't went into a lot of detail on the program, and we will be doing that nearer to it. But when we're looking at the infill opportunities, we're looking at drilling pilots on either side of our targets. So the number of wells could be -- the pilots are both successful with 2 wells. So we could have up to 5 or 6 new wells coming into that, which will be slot dependent on Etame. We've got a redrill in Ebouri, a workover in Ebouri 2-H, a redrill of 4-H and a redirection on Ebouri, one of the other Ebouri locations.
So out of the 7 firm, and I'll exclude the exploration well and the gas well, we've got at least 5 of those wells are new wells. The gas well, obviously, is for fuel gas, and we've got an exploration prospect out there as well. The optional position would take over a number of workover opportunities if we choose to elect them if we feel are necessary given the performance of the ESPs on some of the wells. So that's really what we've kept in contingent.
And the wells, can you give us a sort of ballpark figure for the program or per well?
The really -- I can. I'm probably going to be about $40 million for D&C on a new well. I'm probably going to be about $5 million less on that on a redrill. And for the exploration well, we're going to be down as low as about $17 million to $20 million.
And then very finally, an easy one, I'm sure. In Gabon, on the new licenses, you say you've completed the documentation. That doesn't quite sound like those licenses have been awarded to you.
These licenses have been awarded to us. All parties have signed [ enforcer ], we had an administrative issue that I was discussing with the Minister in Gabon -- sorry, not in Gabon, I was actually in Cape Town last week, discussing it with the minister. We still have to put pen to paper, but he formally announced the licenses that have been awarded to all of us in Cape Town last week. So it's just basically we have to put a signature on a piece of paper, but that's why we've worded it the way we worded it. There is no question over the license whatsoever, just an administrative issue.
And our next question will come from Stephane Foucaud with Auctus Advisors.
The first one is around Canada. So there is this very interesting well to be drilled in Q4 on the exploration side. But I think you didn't talk much about what '25 might look like. Do you plan to do much in Canada in 2025? And would that be dependent on the results of the upcoming exploration well? That's my first question.
Okay. The first question is quite easy. Yes, we probably plan -- we haven't given guidance for '25 yet. We tend to drill a number of wells in Canada to ensure that we keep the GOR ratio in a position that makes sense for us between liquids and gas. We will, I think currently right now, we will be drilling in Canada next year. The key issue here is whether we're enhancing the prospectivity of the south based on the results of this well that will come in or whether we continue to drill in the areas that we've got further north. Now we've got areas worked up. And I think I've said before, we've got an excellent 5-year plan from the team in Canada. So we know exactly where we would like to drill to make sure that we keep the liquid ratio as high as possible. But in saying that, if the well that we're drilling to the south, the exploration well comes in successfully and as expected, that may cause a slight change in sequencing as to where we will target the wells for next year.
So we should expect maybe a capital program similar in Canada than for this year. Would that be something reasonable?
Yes, there or thereabouts. Yes. I mean, obviously, we're not giving guidance yet, Stephane, because we haven't locked in those positions. But I mean, anyone can see that we can't allow the GOR position to go too high due to the gas position in Canada. So we have to keep investing to keep those liquid ratios up.
And my second one, probably for Ron. So the production of Q2 -- of Q3, sorry, was very good. And I was trying to reconcile to see where the production has been so good across the assets. But when I add up the individual production of each asset, I sort of got a slightly lower number, which I think is the production you've got in Slide 4, 26,350. What's the difference between the [ 3 ] 26,350 on Page 4 and the 26,710 headline for the production BOE per day?
You're cutting in and out a little bit, Stephan, I'm finding it a little bit difficult to hear you. But if you could point me to which pages, sorry, you were highlighting?
Yes. Sorry. Can you hear me now?
Yes, I can.
Okay. So it's Slide 3, the headline number for the production is 26,709 a day. And when I was looking at each asset individually, I got a slightly different figure, which is 26,348 on Slide 4. And I was wondering what was the difference? I think it's in Canada, which would suggest it has been a very good production. if you could confirm that would be great.
Yes. And most probably is the individual slide averages coming back through there. I would have to look at my team who presented that for me. But yes, I think if anything, it could be 1 or 2 in those areas just on the averages themselves because these are individual average numbers versus obviously, our total production from a working interest point of view and then divided by effectively 90 -- I guess it was 92 days in Q3.
Our next question will come from Bill Dezellem with Tieton Capital.
I'd like to start with Cote d'Ivoire. The production was up on a daily basis by 35%. And I was hoping that you could help us understand that because I assume that calculation adjusts for a greater number of days in Q3 than Q2 since it's on a daily basis.
Yes. I mean the production has -- well, certainly against our forecast, the field has been performing very well. Recently, we've seen one of the wells take -- come down in Cote d'Ivoire and Baobab, the P-16 well. So we will see a position closer to forecast I think, in Q4. And I think our guidance reflects that position. But basically, we've seen a very strong performance. So we've got the increase because we've had at a higher run rate, 2/3 of Q2 versus the full Q3. But we've also seen the well performing higher than our original forecast that we got from the operator. That's primarily what's been happening. And there's not -- it was only until recently towards the end of Q3, we started to see some issues around the P-16 well.
Yes. I mean I'll just jump in there, Bill. I mean the forecast for Q4 is 4,000 to 4,400. And through October, we were right on the midpoint.
But I don't feel like that totally addresses the significant increase in the daily production in Q3 versus Q2.
I can probably shed some light on that. Yes, Q2 only has 2 months in it because of the closing date versus Q3 has 3 months.
What I was looking at, though, was the daily production as opposed to the total production. Does the daily production take that change into account?
Let me think about that.
It's total production divided by the number of days.
Yes. It's your total number divided by the number of days in the quarter. So it would be 30%.
I mean, at the end of the day, what would have happened in Q2, Bill, is you got more days than we had combined for CDI because it came in on the 1st of May, even though we count from the 1st of April. And then obviously, in Q3, you've got 92 days, so you've got 92 days worth of production at the same time.
I'll take that one offline, but it certainly looks like nice activity there. Let me shift to the BW Energy fields. What is the time line for that relationship for those 2 blocks before you begin drilling and have production?
These are 2 exploration blocks. Now the reason we went into a partnership with Panoro and BWE is because we are -- between the 3 of us, we are the main partners in that whole area for Etame and Dussafu. And the fairway play on blocks G&H run basically flow down from where we produce in Etame down into where they've been drilling and in production in Dussafu. So once we -- once the -- well, in Q4, we will sign and pay the signature bonus. In 2025, we haven't seen the program yet, but we anticipate the program will be seismic acquisition, particularly around Block G, which is the one nearest to us. And then we anticipate sometime in 2026, would be a well being committed into that block. Now production from any successful well is dependent on 2 things. It's dependent on its proximity to infrastructure. So how close is it to Etame versus how close is it to Dussafu and obviously then tying it back. So we're drilling in 2026 per se, assuming rig availability, we wouldn't be seeing any production from that until late '27 by the time you put equipment in place and tie it back to the infrastructure.
and I'm going to try to squeak one more in if you'll allow it. The payments, which I think are roughly $40 million that you are still owed from Egypt, when do you expect that to happen? And does that come as one transfer into your account of $40 million or does it happen piecemeal over time? What's your expectation, how that unfolds going forward?
Well, we've been pushing this for some time. We finally got it to a point where it's recognized and acknowledged by the government. We're keeping it separate from our trade receivables when it comes to the discussions because -- so we're highlighting it as we're not looking for offsets for this. We're not looking for a settlement or keep it settled as we promised to do on a monthly basis with our trade AR. So we're looking for a separate deal on this. And now whether -- how we get to that, and we've been having discussions, our new country manager has been in there having discussions to try and treat this as an extraordinary item. Our anticipation is certainly that we will be looking for a single payment in U.S. dollars to settle this back to position.
On the basis that we've made significant progress through the agreements with the government and including full recognition of our investment and the VAALCO trade name into Egypt, we stood the rig up again last month, and we commenced the drilling activity, both in Ras Gara and South Ghazwa. We're looking in Q1 at the latest to see some movement on that, but the discussions are ongoing. My preference always would be a single payment to your account, but that's certainly where we'll be starting the discussions we have been having the discussions around. And we'll keep pursuing that at the same time, making sure that our trade AR doesn't suffer or be compromised in any way because of this backdated settlement.
We have time for one more question here, and we will take a follow-up from Jeff Robertson with Water Tower Research.
George, in Cote d'Ivoire, with development drilling campaign planned for next year and into 2026, are you all actively seeking a rig for that yet or are you still in the early stages of putting it together?
That's with the operator. I believe they are actively seeking a rig, and I believe they are ready to talk to us about that in early Q1.
And this concludes our question-and-answer session. I'd like to turn the conference back over to George Maxwell for any closing remarks.
Thank you very much, operator. I think we're now something like 17 quarters meeting guidance for production, et cetera. I think the diversification of the portfolio continues to add strength to our performance and derisk the commitments that we make to market. We're entering a phase now of the company where it's got such a stable production base and such a key investable opportunity across a number of platforms as we push the company forward, both with drilling and production opportunities. When we look at the plans we have in Gabon, the plans for Cote d'Ivoire and for Egypt and then also we talked briefly about the plans for Equatorial Guinea, we see the opportunity for the company to move up and more than double its production base over the next 3 years, and that is a very exciting prospect for us.
So you can see the time and effort that the team worked very diligently and very hard to make sure we've got a stable business, not only to maintain our production base and be able to maintain those cash flows, but also to create the opportunities to increase them in the future. And I think that makes it very exciting times for VAALCO for the next few years.
I'd like to thank everyone for their time and listening into us today, and I look forward to talking to you again early in Q1.