Alvopetro Energy. I am joined by Alison Howard, our Chief Financial Officer, and Adrian Audet, our Vice President, Asset Management.
Hi, everyone. Thanks for joining us this morning. Just a few administrative points before we start here. We will be recording today's call, and we will have a replay available on our website later on today. All attendees are placed in listen-in-only mode for the duration of the call, but we will be hosting a Q&A session at the end of the presentation. You can start logging any questions you have now using the Zoom Q&A button that you should see on your screen, and we will get to those at the end of the presentation. If you dialed in by phone, you can send questions to socialmedia@alvopetro.com.
Lastly, just a reminder, we do go through various forward-looking statements and have non-GAAP measures and some oil and gas metrics throughout the presentation, so we do encourage you to read all of the cautionary statements and other disclosures that you can find at the end of our corporate presentation that is posted on our website.
Thank you, Alison. All right, so I think the third quarter was another good quarter for us. If you recall, just looking back, we had a pretty good year last year. Our production was up over 40%. We are off to a pretty good start for. We are getting most of the way through 2026 now, but we are tracking to be up close to 25% again. You can see our third quarter production averaged 2,966 BOE per day. We did have a five-day, or close to a five-day shutdown of our gas plant to finish the planned upgrades at the plant. All that was done in September. We also just announced our October production, so up to 3,200 BOE per day after that expansion was done.
Just a reminder, if you look at the funds flow from operations that we've generated since our key project in Brazil came online in 2020, we've now generated funds flow from operations of $245 million, and 46% of that's been returned to our stakeholders, including close to $80 million of dividends. I think to be able to generate this type of organic growth and have that type of discipline back to our shareholders, we're pretty proud of that. The last comment I'll make, we'll talk about our capital program that continues this year, but as we exit the year with the remaining facilities-focused investments that we have in Brazil, as well as a very busy program in Western Canada, I think we're well-positioned to continue this growth trajectory as we move through 2027.
The one key thing we like to highlight is our exceptional funds flow from operation generation, and it really starts with our operating netback. A reminder, this is one of those non-GAAP measures. It's our operating profitability. We express it in per barrel of oil equivalent, and that's the green bars. That's the profit that you see on our production. So in Q3, starting at the top of the bar chart, we had a realized sales price of just under $71. That included natural gas sales of $11.49 per MCF, up over $0.50 from our Q2 price. The orange bar, we deduct off our royalties. That's the orange bar. Really attractive royalty rates. Our effective royalty rate overall is just over 5%. In Brazil, just under 5%, and in Canada, roughly 15%.
Then we also deduct off here our operating costs, and we've combined our trucking costs in Canada as well. That's the gray bar. Again, really low-cost natural gas production in Brazil. Our operating costs in Brazil were about $5.50 this quarter, and overall, company-wide, just over $6. So that allowed us to generate an operating netback of $60.87 per BOE. That's U.S. Dollar. That's up $1.79 from last quarter. When you look at that relative to our realized price of $70.62, that's a netback margin of 86%, which is really best in class. Thinking about it in total dollar terms, we had revenues of $19.3 million. We generated operating income of $16.6 million. Again, that operating netback margin of 86%. Then you layer in all of our other costs and a very low current tax rate.
We're eligible for a tax incentive in Brazil that reduces our tax rate to just over 15%, and we generated funds flow from operations of $14.3 million on that $19.3 million of revenue. So that's a 74% margin from a funds flow side. So it's really quite remarkable on this level of production, how much funds flow we can generate, and we'll look at that next. This chart just compares this quarter's funds flow of $14.3 to Q2 of $14.1. You can see it's relatively flat. We did have that slightly lower sales volumes in Q3 that Corey touched on, mainly due to that planned shutdown we had in Brazil. That was more than offset, though, by our realized prices. Our royalties were a little bit lower, and other income was higher. Our G&A was also a little bit lower.
Overall, that was offset by some marginally higher production expenses and current tax, and we generated $14.3 million this quarter. On the net income front, there are some non-cash things that go through our net income, so we did see a slight decrease, $1.2 million from Q2 to $8.5 million net income in Q3. The biggest driver of that was foreign exchange. We had a gain in Q2 compared to a very small loss in Q3, so overall, that was the biggest change in our net income there.
All right. This chart just tracks our distributions since we started them in the third quarter of 2021. We have been paying out $0.12 U.S. per share through this year, including our third-quarter dividend. That represents a yield of 7.5% at current share prices. I think I referred to this earlier, but since inception, we have returned U.S. $2.18 per share, or close to $80 million back to shareholders. Just an update on our gas pricing formulas. I think everyone has seen this a number of times. As a reminder, about 80% of our gas right now is being priced under this QDC1 formula, which is the red line that you see here. 20% of the gas is being priced on the QDC2 line. The detailed formulas are in footnote five to the presentation.
At risk of oversimplifying it, about a third of this QDC1 formula effectively is fixed, about a third of it floats based on Henry Hub prices, and another third of it floats based on Brent oil prices, whereas the QDC2 one floats entirely based on Brent. The weighted average between the two is the green line that you see here. As Alison noted, our Q3 average realized price was $11.49 per MCF. The November 1st reset that just happened is around $11 U.S. an MCF, so fairly close. If you look at the futures market as of, I think this was November 4th, so a day or two ago, this is what the forecast looks like as we move through next year.
If you look at the green line, kind of averaging between that $11 and $12 mark through to the end of next year. That certainly helps with our free cash flow generation capacity.
So far in 2026, we have been very busy with all of our technical teams. We have been executing our capital program, which has been targeting the Murucututu 2-2 asset. First off, on the facility side, our gas plant upgrade was completed in September, which culminated in the shutdown that Corey mentioned earlier, that five-day shutdown in September. This upgrade gives us the ability to process larger percentages of the richer Murucututu 2-2 gas. At the Murucututu 2-2 field level, our teams have been working to finish our pipeline expansion and the tie-in at the G location. Both of these projects are required so that we can complete and tie in the newly drilled G2 well and have the ability to put this on production. Both of those projects you can see in the picture at the bottom right.
The pipeline is there on the right with the line pipe laid on the right of way, and the rig there on the left is at our G pad location. We are just in the final phases of moving it out of the way, and then we will start the actual tie-in projects to the flow lines. Both of those two projects are slated to be done in the first quarter of 2027. The teams are also finishing an expansion at the Murucututu 2-2 hub facility, which is the picture at the top right. This will give that facility the ability to flow up to 600 E3M3 a day, and it includes a new separator, a flare, and some other equipment. This project is also going to be done in the first quarter of 2027.
On the drilling side, both the D1 and the H2 well were drilled, then completed in the last quarter or the last few months, and both wells are currently flowing into our production system and into our sales system. We finished the drilling campaign with that G2 well. This project was executed very efficiently. We are encouraged about the log results we saw on this well. We logged over 97 meters of net pay over four Caruaçu sequences and the upper Gomo sequence. That well has now been cased, and like I mentioned earlier, we need to wait for the facilities projects to be done before we finish the completion and then put that well online, which is expected in the first quarter of 2027.
Next year, we are planning a follow-up drilling program at that same G location, as well as an exploratory well at our 183C1 prospect, which is west of Murucututu 2-2 itself.
All right. Moving on to our Western Canadian business unit that I think we've assembled a pretty impressive position here. If you recall, we did a couple of initial joint ventures with an initial partner. We'll call that the 2025 JV, focused on the Mannville Stack heavy oil play fairway. That was focused on the Saskatchewan side of the play in this kind of green outline that you see here. Then in the third quarter, we announced a new joint venture, the 2026 JV, with a new counterparty. The terms of that are basically Alvopetro is going to fund five earning wells here. We've started drilling the first of those five this morning, actually. Then as the terms of that are basically we earn 75% interest in those wells before getting payout, and then after payout, we earn a 50% working interest.
As we drill the wells, we earn a 50% interest in all the surrounding undeveloped land. I think it's certainly a nice transaction for us. It gives us access to kind of an accelerated drilling program here in the fourth quarter. We're getting access to two of the leading technologies that are being applied to this play, so open hole multilateral wells and single leg horizontal wells with recirculation strings. We're drilling the five wells across five different core areas into some very attractive geologies. Then the other thing is with our initial joint venture partner here, we actually did just finish drilling two additional gross wells, 0.8 net wells. Those were brought on production in October.
They go through a cleanup flow period, and then we fill the tanks, and ultimately you'll start to probably see sales from those wells show up in our November and certainly December sales numbers that we announce. I think if you put this in perspective, this is one of the leading plays in Western Canada, and through these two transactions, we very quickly built, I think, a pretty impressive inventory of opportunities. After earning here, our land position will be over 133 sq mi of gross land, over 175 tier 1 drilling locations. We're pretty excited about the business here, and we've got a very busy fourth quarter ahead of us. Just to summarize again, Alvopetro certainly offers, I think, an attractive investment proposition, whether you look at it on a value, yield, or growth basis.
I think we've got some exceptional quality assets that are really. That ratio of funds flow to revenue that we can generate really highlights the strength of our assets, and we've got some highly strategic infrastructure, and I think a pretty attractive and disciplined capital allocation model where we've been able to have some attractive organic growth and pretty disciplined return of capital to our stakeholders. From a value perspective, we're trading at less than two-thirds of our 2P NPVs. I mentioned the yield, 7.5% yield. From a growth perspective, I think this is a very busy time for us, and although we've had two successive pretty good years, I think as we move through into next year, we're very well positioned to continue that growth trajectory and unlock a lot of value for shareholders.
Okay. We have some questions. We do have some from social media, email, so maybe I will start with some of those. There are quite a few questions actually around facilities expansion and capacity. How are you managing facilities capacity constraints between your plans to increase Murucututu field and pipeline capacity to 600,000 cu m per day and your existing UPGN capacity, considering the contribution of higher heat content and liquids-rich gas from Murucututu, along with your commercial offtake relationship with Bahiagás?
Okay, so I think Alison has combined a few questions into there, but I will try and cover them all off. Our capital program this year really was kind of dual pronged. We had a facilities component and a drilling component. The facilities part of it really has been to address the levels of success that we have had at Murucututu. As Adrian mentioned, the UPGN expansion was completed in September. Most of that related to improving the condensate stabilization process at the plant, and we did add some additional redundant compression as well. But the biggest reason we did that is it will allow us to produce roughly about half of our gas from the higher heat content gas that we have at Murucututu, so 50/50 relative with Murucututu.
It also should give us the ability to grow the nameplate capacity of that plant up to about 600,000 cu m a day, which is just over 21 million cu ft a day. In parallel, as Adrian walked you through those facilities projects that are actively going on in the field right now, we are expanding the field production facility at Murucututu and the related pipeline takeaway capacity to increase Murucututu's field takeaway capacity back up to that kind of same number.
Longer term, if you look at those two things together, if we move towards an even higher percentage of gas coming from Murucututu or other hot gas, like for example, the 183C1 exploration prospect that we are going to drill next year, to do that, we would have a next plant expansion at the gas plant to basically allow us to remove the propane portion of the gas stream from the sales gas. That is something that is actually being engineered right now, and we will continue to work through that. But that gives us the next layer of flexibility. The last part of that was related to the interaction, I think, with Bahiagás. I think as demonstrated in the last couple of years here, in 2025, I think we increased our firm commitments to Bahiagás by a third. In 2026, we increased them by another 25%.
And then as these projects get completed, we'll look to continue to complement that. The city gate that Bahiagás built at our physical gas plant and the pipeline capacity from there is pretty robust. I think it's about 70 million cu ft a day. We've got lots of room to grow there. The relationship with Bahiagás, just so everyone understands, we typically look at that annually, and then we'll commit these incremental volumes on kind of a one or two-year period, and that's kind of what we did. That QDC2 line that I reviewed in the presentation, that's about 20% of our sales right now. We had negotiated that, I think, near the end of 2025.
Okay, just following up on the capacity, because there's some additional questions around if we have sufficient drilling inventory. There's another question about, previously, back in 2022, we showed a long-term vision of Brazil of 6,000 BOE per day, and now you've added on Canadian operations. Is the long-term vision for Brazil still 6,000 BOE per day, or are you going to be relying on Canada to get to that longer term? Maybe the first part is on the drilling inventory and filling this capacity that we're building for.
Alison's now come. I think that was three questions again combined to one. Okay, I'm going to try and go back to 2022 in my mind, so someone's testing me pretty well here. As I recall, we had presented a number of kind of some stacking production charts that were a success, particularly at Murucututu 2-2, on both the reserve and resource development side, as well as kind of a vision for what that business could grow to, which was basically kind of doubling what the original plant size was. I think if I build on the response that I made to the previous question, I think you can see we've been growing our business in steps. We're up 40% in 2025, up about 25% this year.
We're positioning ourselves with the capital program, both facilities and drilling, for the next step to be about another 20% up with that. Another good way to maybe look at how we think about what the right size of facilities capacity and gas sales capacity is, maybe in a quantitative way, is our reserve life index. If you look at the end of last year, our reserve life index, I think on a 2P basis, was about 12 and a half years. That's a pretty good number. If we have continued success at Murucututu 2-2 and export nearby exploration and things like that, and that number starts to grow higher than that, we have a choice, basically. Do we produce at that same level that we're building towards for longer, or do we expand the plant and the gas sales again?
I would say if that reserve life index gets considerably longer than that 12.5, what it is pointing you to is that, okay, we should build more steps and continue the growth towards that kind of 6,000 number. That is just in the area that we are talking about there. If the number falls below that, then it tells you we should be focusing more of our attention on drilling new opportunities and building the inventory and things like that. Hopefully, we are doing both of those things. I think the 6,000 goal is still a rational goal, especially when you consider things like the 183C1 exploration prospect that we are drilling next year. We just added over a 460 sq km exploration land position in the adjacent basin, in the Tucano Basin. Although that is early stage, that has a lot of potential for a company our size.
Obviously, it is success-based, but that is what that looks like. Then from a numeric perspective, I talked about the 20% uplift in Brazil, so that would get us just shy of, say, 4,000 BOEs per day. The Canadian platform, we are not putting detailed production guidance out there, but if you look at the type curves that we presented and the inventory that we have, depending on the levels of success and the pace at which we are drilling those wells, which is somewhat oil price dependent as well, we certainly think that that asset has the potential to grow to a couple thousand barrels a day without adding too much more to that inventory. I think things are looking pretty good. Then the drilling inventory, I think I just answered part of that.
I think next year we will have a little bit of a balance between exploration and ongoing development at Murucututu, which will, I think, help us position us quite well for that next stage of growth there. Then the Canadian program, we have got a pretty deep inventory of opportunities there. We will drill these next five earning wells, we will get the results from those, and then we will design a capital program for next year and the years beyond. But I think there is a pretty deep inventory there. Then I talked about the new exploration position in the Tucano. But we are always looking for new opportunities, and we have a pretty long-term view on the business.
Maybe we will just jump. We have a couple questions on Canada. It looks like Canada activity is increasing now, but there was relatively little activity earlier in the year. Can you comment on why that was, especially in the context of the oil pricing being so high in that period?
With our initial partner, we are trying to work through a collaborative drilling program with that counterparty. It ended up that the timing of the next two wells, we just finished drilling them, and then we are going to work to design next year's program. But with the addition of we just added this Courser second joint venture, the 2026 joint venture in September. I think we have pretty quickly moved to drilling there, and we look to have we probably won't get all five wells drilled in the fourth quarter. They will probably extend into the first quarter, but hopefully at least four of the five will be drilled in the fourth quarter. It is a pretty active program.
In Canada, one of the questions is how many total wells are we drilling in Q4? We have just finished the two with the original partner, the 2025 venture partner, and then we have these five earnings wells with the 2026 partner. Then, as m entioned, that could potentially, some of those could be into early 2027. The other question is, how many in 2027 after that, I guess, would be the question on that.
I think we are going to define that based on the results that we see, and stay tuned.
Staying on the Canada front, how have the existing wells in Canada produced relative to your type curve declines seem to have accelerated recently, and do you have an expectation of flow rate for the two wells that just came on production?
Yeah. Unlike maybe these kind of individually higher impact wells in Brazil, partly because we have partners and partly because the data is a little bit delayed publicly, we're not going to kind of announce initial production rates from individual wells. The other nuance with these heavy oil wells that we're drilling is you go through a cleanup period where you're producing back the drilling fluid, and then you're slowly kind of ramping up the oil production. The pace at which that starts to show up in our sales can vary.
If you look back, it's not in this presentation, but in some presentations we've had of late, the type curves we've got kind of a range, but if we can be between 150 and 200 bpd gross per well and cumulatively produce upwards of anywhere above 100,000 bbl per well, ideally in the 120 to 150 or 180,000 bbl per well, these wells can generate some pretty impressive rates of return, especially with current oil prices.
Okay, let's move back to Brazil. We have a number of questions around our most recent wells that we've drilled there. On the H2 well, we just announced initial kind of production results from that well. What rate do you expect once it's cleaned up, and how does this compare to what you expected before drilling?
Yeah. I think we've had kind of variable results from our Murucututu p roject, which is a little bit to be expected. Geology is variable after all. Some of them probably below kind of what our expectations were, and some certainly well above it. Maybe I'll talk about it all together, and it's a little bit difficult. Like, we announce net pay in our presentations and things like that. It's a little bit difficult to contrast them apples to apples because petrophysics is more complicated than just the net pay, but I'll try and give you a little bit of a sense. And every well is a little bit different. The data that we get from each well is a little bit different, but a good example would be our 183 D4 well, which was one of our better wells.
We were only able to get that drilled to kind of the bottom of Caruaçu sequence 6.2. We had some challenging hole conditions in the well. As a result, we cased that very quickly without open hole logs. We had good gas shows while drilling and cased hole logs. We basically defined the net pay and completed that well based on that. The H2 well, the good news is we drilled that into the prospective resource area, so it looks like we were migrating resource to reserves here. That well was drilled in a kind of down dip orientation, and the net pay that we had defined was just in the lower two sequences of the Caruaçu formation. This is a lot of information.
If we contrast the G2 well that we just drilled, we were able to actually drill that well very effectively all the way through up and tag the upper Gomo portion of the reservoir. We got all four Caruaçu sequences into the upper Gomo. We were able to get sidewall cores, open hole logs. We were able to do all that, I think, for about 10% under our AFE budget. We've got, I think, some pretty impressive gas shows while drilling. With the open hole logs, we defined about 97 m of potential net pay through all four of those Caruaçu sequences and the upper Gomo sequence. That structurally, that G2 well is about 65 m up dip or up structure from that good well that we drilled with the 183 D4. Hopefully that kind of puts some of that in perspective.
Certainly we've had the H2 production results are below the D4 well. Like I said, it was only completed in two of those sequences. As far as cleanup goes, we've recovered a decent amount of the completion fluid. We'll see how the well performs. All these wells, we'll continue to monitor that, and we also run production logging tools and try to improve our understanding of what's happening on the subsurface.
Great. Maybe a little bit more on G2, because there's a lot of questions around the significance of the 97 meters of potential net pay, and also around the timing of the completion, and will that be done in Q1, and why aren't you doing that right away?
Yes. The first part of that, I think I touched on in the earlier response. We are pretty happy about this between the gas shows that we saw while drilling and the quality of the net pay that we see on the open hole log. We are certainly looking forward to getting this completed. The timing is more driven, I think Adrian talked about that. That G well pad, unlike where H2 was drilled, that H2 well pad was already pipeline connected. It was off the 197-1 lease, so we were able to put that on production right away. The difference is that G pad was just recently constructed. That is the first well drilled off of it, and we always had this facilities plan to tie that back into the 183-1 lease, which was that upper picture that Adrian showed.
It really has to do with the fact that when we complete, stimulate, and bring these wells on production, we want to do that as quickly as possible to get all the fluids back out of the well. What it means is we are going to make sure that we have that pipeline connected, and then we can go from completion to production to sales instantaneously, basically.
Are there plans for any further drilling in the area around the H2 well west of the fault?
Yeah. The production results and the evaluation of that is just brand new, so we will integrate that into our models and look at the drilling program over the next couple years, and we will have the benefit of seeing how that well performs. But I would say probably, we have not announced our 2027 capital budget yet, but with that new G pad that we have got, I would imagine that we would focus our attention on that. As Adrian mentioned, we are also going to allocate some capital to that adjoining or adjacent Caruaçu exploration prospect at 183C1, which just sits immediately west of Murucututu .
Yeah. There are a couple questions about how many Murucututu wells are planned for 2027, and in what order.
Yeah. We will probably come out with that in the next couple months as we firm up our rig schedule. Yeah.
Yeah. There also is a question about the 2027 CapEx guidance, but as Corey mentioned, we have not finalized that yet. That will be released when that is all final and approved. On to Tucano, what does the first phase work program involve?
Yeah. Good question. I think the nice thing about this is we were able to add a pretty significant exploration land position at a very low upfront cost. The work commitments, there is one legacy field or pool. We have three years to complete that, and the work commitment is notionally a recompletion on a workover of an existing well. We have three years to do that. The bigger exploration blocks, we have six years to meet the initial commitments, and they are defined in work units. It is not an easy answer to your question. It depends what we see, but there are 200 units per block. The way it works in Brazil is we can fulfill those individually by each block, but we can also aggregate those work commitments.
If we have a prospect that we really like on one of the blocks, we can satisfy all the work commitments by drilling one well. From a work perspective, what we will do is there is a bunch of available seismic. We are going to reprocess that and firm up the leads that advance into prospects, and then we will license. If we like what we see, we will license those locations, construct the pads, and then drill the wells. Practically speaking, we will be doing the technical work next year, and that is something from a more meaningful capital exposure wouldn't be until 2028 or 2029 probably.
Okay. There are a couple questions around gas demand. One person noted that October sales volumes in Brazil were already above our firm gas contract, and once Murucututu 2-2 goes to 600,000 cu m a day, how much interruptible or spot demand is there? Perhaps you can touch on overall gas demand in the region and whether that will constrain us. A lot of questions today.
Yeah. We can sell gas under the firm formulas and volumes that we have within our contract. We have historically, and to some degree in October as well, delivered above that, which then becomes what is called interruptible or flexible gas. To be honest, our ability to do that is sometimes market dependent and dependent on what other peers are doing with their production during the period. We have typically locked these things in steps by adding to our firm volumes, but we do have that flexibility. From a market perspective, at our current production levels, we are, I think, around 20% of the gas, meet about 20% of the gas demand in the state of Bahia, ballpark.
I think between the facility that we have at our location that I touched on, the city gate and the pipeline capacity from Bahiagás, we have got a big base of industrial demand that sits just 15-20 km to the south of us. All that put together, I do not think there is any huge constraints relative to the market share that we have got right now, relative to kind of our business goals here.
With President Lula being reelected, do you anticipate any changes in Brazil's energy policies, taxation, royalties that could affect Alvopetro?
Yeah, I think, we've been operating in Brazil for quite a while, so we went through kind of more left governments, more right governments, the whole bit. I would say overall, the regulatory environment in Brazil's been quite stable. The other unique thing about Brazil is there's a lot of different political parties. So in the first round of elections, the composition of the lower house and the upper house of the government was already basically set. Those bodies of governments, I would say, are center-right-leaning, pro-business representation, which is a little bit different than the president right now. So what it does is it creates some pretty tight guardrails around what can happen. But overall, I would say, we don't expect a lot of volatility in kind of the regulatory and tax situation in Brazil.
I think the energy industry is recognized as a pretty key industry in Brazil. To fund the social programs that you want to fund, it's a pretty critical part of the economy.
With funds flow of over $14 million this quarter and dividends of approximately $4.5 million, you have excellent dividend coverage. As your CapEx increases, do you anticipate maintaining the current dividend, or could capital requirements influence future distributions?
Yeah, we don't give guidance on what the dividend might look like a year from now, but what I would say is, we did make a conscious decision to accelerate some capital that was originally slotted for kind of the first half or even into the first, say, the first half of next year into this year. That was the H2 well and the G2 well that we've been talking about. We certainly have spent kind of more than what our historical run rate has been this year, but it really was an acceleration of capital. Because of that, I think we've been kind of prudent or deliberate with our dividend increases, which is a good observation. But it's mostly related to that. Although we've grown production and cash flows through 2026 quite handsomely, we did increase the dividend by about 20%.
But yeah, I think we certainly have room to grow that, but that's ultimately a decision for the board to make.
Sorry, there's one other question that I've just seen now on the socialmedia@alvopetro.com email. I think we've touched on this somewhat, but they're asking for additional information on the status of 183-D1 and whether we've seen any improvement in production since the initial flow test.
Yeah, I'd say that well's been pretty consistent, and it looks somewhat similar to the H2 well.
And then a follow-up to that is, are changes being made to the completion approach on G2 based on D1 and H2 results?
Well, again, I talked a lot about the differences, I guess, earlier on. The main thing is that the G2 well is 65 meters up dip or up structure from the D4 well. The gas shows look as good or better than any well that we've drilled. So we have put 13 sleeves in that well. I'm not saying we'll complete all of them, but I would imagine, we've got the ability to complete all four Caruaçu sequences and the Upper Gomo, and we're going to make those decisions here over the next probably 30 days and be executing that early in the new year.
Okay, and we just had another question, a couple questions come in. You're holding a lot of cash and equivalents on the balance sheet. Is there a reason to hold so much?
Yeah, no, good question. We did add a small tranche of debt at the end of last year. The way it works in Brazil is when you do that, you draw on it, and you have the cash on the balance sheet. So yeah, good observation. We haven't effectively used that yet, but we wanted to have the flexibility to do things like accelerate this capital that I talked about. So I think it was a prudent thing to do to have that flexibility. And our CapEx here in the third and fourth quarter are certainly higher, and that's allowed us to do that. I think between our free cash flow generation capacity that Alison highlighted and that balance sheet strength that we've got, I think we're in a pretty good position as we exit this year.
Okay, then we had one question about the buttons that Corey and I are wearing. You did not get to have one on today. These are poppies, and we wear them in recognition of military people that have served for us and died for us for the freedom that we have today. It is for November 11th, but people generally start wearing them end of October to November 11th. That is it. That is all the questions.
All right. Well, thank you again for everyone attending. Thank you for your support, and if you have got any questions, feel free to follow up with us after the call. We look forward to updating you next time. Thank you.
Thanks.