Alvopetro Energy Ltd.

good morning uh thank you for joining us today for our second quarter 2022 results webcast i'm corey rutan president and ceo and this is alice allison howard our chief financial officer and i'm going to turn it over to allison to start uh thanks corey and good morning everyone uh just a reminder that this webcast is being recorded today and there will be a replay available on our website shortly after the call

All participants are in listen-only mode for the duration of the webcast, but we will be hosting a Q&A session after our presentation, and so we encourage you to use the Q&A feature within Zoom. You can insert any questions by hitting that Q&A button that you see on your screen, and we will go through those at the end of the at the end of the call and if you are dialing in, you can send in any questions to email at socialmedia at elvopetro.com and we will also get to those at the end of the presentation. These are our cautionary statements. I'm not going to go through these in detail, but I do encourage you to visit our website and review those within our corporate presentation. So just starting things off today, I think you'll have seen that we did a financial statement restatement of our prior year financials. So I just wanted to give a bit of a summary on that. So this all stems from accounting for actually the 2012 acquisition of these Brazil assets and purchase price accounting with respect to some fair value adjustments. Amy Nunez, Under ifrs we are required to carry certain fair value adjustments in local currency of our subsidiary, which is the Brazilian hey I. Amy Nunez, And we had carried these in US dollars, and so, when we correct for this and we carry and local currency every period and date it gets revalued. based on the new US dollar foreign exchange rate at that time. So what happens is when we look at the adjustments in aggregate is there's an overall reduction in the carrying value of our E&E and PP&E assets on our balance sheet just due to the devaluation of the Brazilian HAI relative to the US dollar since 2012. That's Catherine Vladutiu, CA OSDSU, Partially offset on the balance sheet by the recognition of a higher deferred tax asset, because we have lower accounting carrying value. Catherine Vladutiu, CA OSDSU, And then, overall, are retained earnings actually increases from what we reported previously due to lower impairment charges in US dollar equivalent and lower depletion expense and that higher deferred tax recovery. So I think the key takeaway here is that, you know, this doesn't have anything to do with our operations. There's no change in our cash or our working capital. There's no change overall in funds flow from operations that we reported or cash flows from financing or investing activities. There's, you know, there's no change in our business overall. These are all accounting adjustments, but I do encourage you to review the financial statements and the note disclosure that goes through this in even more detail. And of course, if you have any questions, feel free to contact me directly and I'm happy to walk through that in more detail. And I will now turn it back over to Corey.

All right, thank you. So we obviously continue to post some pretty strong production results ahead of the pre-commercialization expectations that we'd set. Our Q2 production was impacted as we previously announced. by our planned five-day shutdown of our gas plant in connection with the expansion, which is now complete. And you can see our July production was another good month for us at over 2,500 barrels of oil equivalent per day, which is up 7% over our Q2 average. With the expansion now complete, we have the capacity to process and produce up to about 3,000 barrels of oil equivalent per day. If you look at our past production, obviously it's been incredibly stable. The limiting factor really was the plant capacity. Going forward, our production will be more dictated by production availability from the unit in combination with our partner, as well as the timing and quantum of future production additions from our new projects, which we'll talk about during this presentation. So that being said, you know, we do have the ability to produce at higher levels, which is great, but you may also expect a little bit more volatility, certainly than what you've seen from the past experience. This is a graph that we show on all our quarterly earnings calls. It shows our gas pricing mechanism within our gas sales agreement. Just as a reminder, the three different gray dashed lines that you see there are the three international benchmark prices that get used to calculate our realized gas price, those being UK NBP gas price, US Henry Hub gas price, and Brent oil equivalent. The black dark line is our actual realized price for Alpo Petro. If you recall, we had a very large increase in that effective February 1st of this year, it's about a 50% increase. And then in addition to that, we had an appreciation of the local currency, which actually ended up meaning that we realized through the first half of this year, a price higher than our contractual ceiling, which is noted in green. We then did have another price redetermination. We just announced that that was effective August 1st, just 10 or 12 days ago. We did have an increase in our U.S. dollar denominated ceiling price by about 6% up to over $10 U.S. per MMBTU. But because of this appreciation that we benefited from through the first half of the year, the local currency denominated price stayed pretty consistent at $1.94 per cubic meter. The net effect using the July closing FX rate was just over $11. us per mcf if we look at this going forward so the red the red dashed line to the right of that what we're doing is we're forecasting that the price is going forward based on the strip pricing on on august 10th so these are the market uh forward prices for each of the the benchmark prices you can see the nbp price is actually off the graph uh to the north and or to to the top in the near-term portion The net effect of that is if you calculate using the formula, you get this dark blue line. And as we've talked about before, because of our ceiling, obviously our price would match the ceiling. And what's changed from the last time we looked at this is this gap has widened quite a bit and it's also extended. So we now are forecasting based on these prices that we would be at the ceiling all the way through the 2027 period that you see on this graph. um and what this really means is that commodity prices have the ability to be actually quite a bit lower than these forecast prices before we would realize any reduction in our realized gas price so it really does highlight the hedgy nature of our gas sales agreement uh so this chart here shows our operating net back which is

the height of the green bar that you see there, and that's our profitability per barrel of oil equivalent. So we start at the top. There is our realized sales price. So Q2 was just just over $73 over $11 higher than Q1. Now that we had three full months at that ceiling price that Corey was just talking about. And then we reduce that by royalties. You see an orange and then production expenses in gray. And we had a record net back for Elbow Petro in Q2 of almost $64. So over $10 higher than Q1. And that line you see at the top there is our net back margin. And that's our operating net back compared to our actual price in the period. And we would say that Elbow Petro has best in class operating net back margins. This year to date is 87%. And last year, Amy Nunez, average 82 or 83% and and if we look at the next slide here this compares our net back margin to other publicly traded. Amy Nunez, Oil and gas companies that have released Q2 and are operating in Latin America or Canada and elbow petro at 80 87% is close to 30% higher than the average of 68% so that just shows the profitability of our production. And with that profitable production, our funds flow improved 1.5 million in Q2. So despite that 6% drop in production with that plan shut down in May, our overall funds flow, again, also record funds flow for Alvopetro of 12.4 million. From a net income perspective, we did see a decrease. If you recall, we talked about this on prior calls. We are subject to some foreign exchange fluctuations that are non-cash in nature, largely on our intercompany amounts, because under IFRS we are required to reflect the foreign exchange gains or losses that our subsidiary has on amounts that we've lent them, even though the balances don't show up on the consolidation. It's a bit of an accounting adjustment, non-cash in nature, because we had a $5 million foreign exchange gain in Q1 and a $3 million loss in Q2. That's a swing of $8 million on our net income, partially offset by lower deferred tax. But overall, our net income was $6.6 million, which was $4.5 million lower than Q1. From a working capital and overall financial resources position, we're still very strong with these record quarter we had here. Working capital, which is current assets, less current liabilities. That's the green bar that we show there, $11.6 million as of June 30th. With cash, which is the black line of close to $14 million. Our credit facility is that orange line and we repaid another two and a half million in the quarter. So our balance outstanding is actually two and a half million, which is well under one month of cashflow. And if you look at the height of that green bar relative to the orange line, that's the difference there is what we call our working capital net of debt. And that increased to 9.1 million. So our working capital exceeded our credit facility by 9.1 million, which was an improvement of 1.8 million compared to March 31st.

All right, thank you. So like Alison said, our second quarter was our strongest quarter yet in terms of fund slope from operations up to $12.4 million. You can see that on the line on the graph on the top left here. That was a 14% increase quarter over quarter and 127% increase from the funds flow we generated in the second quarter of last year. This graph on the upper left is meant to just show how we're allocating that cash flow out pursuant to our capital allocation model. You can see in the first year of our project coming on stream, the vast majority of this was allocated to repaying debt and paying interest, which is in the orange bars. We did that in a very accelerated fashion. There was a small amount of investing in capital projects happening, which is in yellow. But based on the strength of our results, we did initiate our dividend program about six months ahead of schedule. You can see that in the green bars there. We started that in the third quarter of last year at a level of 6 cents US per share. We did increase that by a third in the first quarter of this year, coincident with the gas price increase that I reviewed earlier. And then the other thing to note here is you can see that we've been investing more in earnest here starting in the first and second quarters of this year with a more balanced approach and obviously complementing our strong results with reinvestment in organic growth that you see in yellow. So we've now got two full years of operations under our belt and you can see in those two years we've had funds flow from operations of close to $56 million. Just under a third of that's been reinvested. A little under 30% of it has been dedicated towards accelerated debt repayments and interest, a little under 20% to dividends. And at the same time, as Alison noted, we've built financial resources over that time by over $9 million. So that takes us over to our organic growth plan. To reiterate, our near-term goal is to get to 18 million cubic feet a day with a longer-term vision to basically double that up to 35 million cubic feet a day. It's a three-pronged approach, starting with our core assets, our cabaret unit and our midstream infrastructure. I'll show you what this looks like, but the gas plant expansion that we've talked about was completed in July. And we've got some growth at the unit that we're underway with the unit C drilling. It's a combination of development and exploration that I'll review. We had a two well exploration program this year. We're very excited about the results. I'll review those, but we're off to a great start. And then we've got our America 2-2 GOMO project where GLJ, our independent reserve evaluator, has assigned a combination of 2P reserves and contingent and prospective resource. We've got a multi-year development plan here and I'll review our progress. So just talking about the unit, obviously it's been performing very well along with our partner here. We did increase the gross production plateau capacity that we had originally agreed to up by a third, up to over 21 million cubic feet a day. As a recap, The vast majority of the production to date has been coming from the east side of this main bounding fault. You can see it on the seismic section on the bottom right here. There's six wells. You can see it on the cross section. So the vast majority of the production comes from this Karasu formation on the east side of the fault. When our partner is dispatching gas, this well on the west side of the fault also produces from the shallow Pajuka sands. Mayor Mrakas, So of note we're currently drilling with our partner, the unit see well targeting not only a development. Mayor Mrakas, upside in the bazooka and these deeper sense that were encountered in that original well, but more notably or, most notably. Mayor Mrakas, it's an exploration target targeting the same Kara Sue sands that we produce from on the on the eastern side of the main bounding fault. in this western down throne location so with success here we're hopeful that we can expand the unit production capacity even further and we would expect to have results announced from this hopefully later this month on our gas plant expansion like we said that's uh complete the capacity is now half a million cubic meters a day which is 18 million cubic feet a day uh the the project consisted of adding a fourth compressor that you can see right here a Jewell Thompson valve at the inlet to the cold separator that you can see right here, and then also a vapor recovery unit that you see right here. So at the end of the day, the project not only results in the higher capacity that we've talked about, but it further stabilizes the condensate, results in better condensate yields, it minimizes our flaring, and we're better equipped to handle richer gas like the gas that we're going to be producing from our GOMO America 2-2 project. Moving on to the conventional exploration, the 182C1 well, we talked about this on our last call, but just to recap, because we're in the middle of testing it right now, this was a well that encountered a nice 30, so this log on the left-hand side here, the yellow highlights where we've got sands within the the the aqua grande formation and there's 36 meters of growth sand here of that 36 meters. And you can see this on the red pay flags on the right-hand side. 25 meters of that means our net pay cutoff. So 6% porosity, 50% water saturation, and 50% B shale. We've perforated pretty much this whole section, and we expect to announce results again also this month. In addition, once that's done, we're doing the completion actually with the drilling rig. Once that's done, we're going to move the drilling rig about six meters over and we're going to drill a well further to the east from the same location. So it might be hard to see my cursor, but it's mostly east and a tiny bit north is the bottom hole location. And the objective of that is kind of threefold. First of all, that will help us define the aerial extent of the Agua Grande it'll help define the reservoir quality further away from the main bounding fault because we're quite close here. And then the third thing is because what happened is as soon as we drilled through, virtually as soon as we drilled through the aqua granite formation, we ended up crossing the main bounding fault. So we didn't end up drilling through the Sergi formation, which was the second target in this formation. And in that more easterly location, We fully expect to still encounter that, and we'll talk about the surgery a little bit on the second well that we drilled, which is our 183B1 location. We just recently announced results from this. We're very excited about it based on logs as well as fluid samples that we collected during that process. We've got a multi-zone discovery here, it looks like, over three different formations. We've assigned 34 meters of potential net pay based on that. We're organizing to start the formation testing here in September. And just to walk you through what we've got starting from the bottom, this is the surgy formation. So again, the yellow highlights the sands within here. It's about a 78 meter gross section. For reference, the surges typically about 220 meters. So we didn't actually, you know, we stopped because we scrubbed the bit and our rates of penetration dropped and we looked like we had a pretty good well. But our next wells would drill deeper and we would fully expect to encounter the full surging formation here. Of the 78 meters, you can see again with the red pay flags that we've got here, we've assigned 17.5 meters of potential oil pay where the little black arrow sits right here, we actually recovered light oil from that, which is encouraging. And then the last thing to talk about in the surgery is all this red cross hatching that you see here is denotes areas where we had bad hole or well bore washouts. So it makes it difficult to rely on the log analysis, but while drilling, it looked obviously very similar to everything else. And we think we have, possible additional net pay in all these red crosshatch sections that we will be able to validate through the testing operation. If we move up whole, this next section that you see here is the Agua Grande, same formation that we talked about in the last well. Of that, 11.4 meters of it meets our net pay thresholds. Again, this black arrow here shows where we tested gas from this. The other thing to note is that we've got a very nice looking section at the top of this. So there's about three meters of the net pay here that has average porosity around 17%. It obviously peaks at higher than that. And what that's indicative of is that this is an aeolian facies that has typically very good permeability. And you can see the porosity here. So we're optimistic about that. And then the third thing as a bit of a bonus here, this certainly wasn't envisioned in our resource report that we did in advance of this, but we've got this very nice looking candace sand. It's 5.4 meters or 5.3 meters of net pay here. And again, very good porosity averaging almost 16%. And with the little black arrow, again, we did recover light oil from this as well. So we're really excited about this. Um, and hopefully get started testing this in early September. Moving on to our America Tutu or GOMO project, the key here initially was getting all our production facilities in place. You can see a picture of that in the center. We're in the commissioning phase. We're just waiting for an inspection from the A&P to approve the fiscalization system, and then we'll be in a position to turn the 183.1 on production. And then at the same time here, we're constructing the flow line from the 197-1 well and pad to tie that back into this facility at 183-1. And you can see a picture of that on the right hand side. That's going quite well. We're over 65% complete on that project. And then once all that's in place, we obviously turn both those wells on and then we'd be in a position to start a multi-year development drilling program Obviously, with the success we've had on the conventional exploration side, we are planning some follow up there. So the timing of the drilling of those wells is looking more like the very early part of 2023. One of the other things we announced just last week is our inaugural sustainability report. James Forrest, Norcal PTACC, he's been I think just yesterday, you can link or website on the bottom left where that where you can get an actual copy of that. James Forrest, Norcal PTACC, And the report really highlights our accomplishments and our focus on growing a strong and sustainable business. but it also creates visibility on our approach to ESG. We've talked about this, but our commitment certainly to social and environmental responsibility goes well beyond what's required by Brazil's already stringent regulatory requirements. I would say our approach, it really focuses on trying to minimize our impact. Our team pays special attention to preventing erosion and preserving biodiversity. A good example that just last year was the construction of our eight kilometer America to to pipeline. We designed that in a way that 90% of it followed either existing rights of right of ways or use directional boring. So horizontal directional boring to to minimize our impact. We were able to spare, you know, We had 65% fewer trees and vegetation impacted than what we were permitted for, and we're pretty proud of that. We did finish our scope one and scope two emissions intensity as part of the project. 4.7 kilograms of CO2 equivalent per BOE is certainly top decile. It's about four times less than what a typical or average US producer would be. um from a consumption perspective obviously burning natural gas relative to fuel oil has another over 50 reduction in greenhouse gas emissions and lastly you know we don't produce a lot of water but any water that we do produce now or in the future it all gets re-injected from a safety perspective we've had two years of operations now zero lost time incidents And from a community perspective, we have allocated 20 cents per barrel of oil equivalent produced to invest in voluntary social programs. And the report highlights the first two of those programs. And lastly, on the governance side of things, we've always had a high standard of corporate governance. We inherited it from our predecessor company, Petra Mineralis. It's based off our value system that governs all of our interactions. So in conclusion, I certainly think Algo Petrol continues to offer, maybe more than ever, a very attractive investment proposition no matter what your investing focus is. From a results perspective, obviously we continue to deliver ahead of initial expectations. Q2 was another record quarter for us. July, another very solid month of production. Attractive gas prices, leading operating margins or profitability per unit produced. We've got a strong balance sheet, great free cash flow generation capacity that really helps underpin our much more balanced reinvestment sorry, reinvestment and stakeholder return model. For value investors, we're trading at under 60% of our 2P net asset value. And that's before taking into account these recent exploration results and before taking into account the full deep base and GOMO potential that we have. We're trading at about 3.5 times annualized funds flow. For yield investors, we're delivering just under a 6% yield right now. with quarterly dividends paid in us dollars and for growth investors obviously i think we've got a very exciting capital program this year some exciting early results that we'll be able to define more here in the very near future so there's a lot of near-term catalysts especially when you consider the quantum of those relative to our market capitalizations So with that, we're going to turn it over to the Q&A. I see people have already started to log those in. Just as a reminder, you can click the Q&A button within Zoom, or you can, if you need to, email them to socialmedia at albopetro.com. And I'm just going to stop sharing the presentation so that we can see us a little bit better. All right.

Okay, perfect. We'll start out with some questions on the plant expansion. How quickly can processing operations ramp up to 18 million cubic feet per day, and do we expect to see production at those levels in the near term, or does it require 183.1 and 197.1 to come online?

uh yeah so so there's still a little bit of fine tuning that's happening at the plant when you see our august numbers uh which we'll announce in early september uh you'll get a sense for where we've been producing um but You know we're ramping the plant up towards the full the full capacity, we have been producing kind of ahead of where we've been which is great, let us get the whole month complete. But like I said, the main thing that's going to impact the production in the in the near term is just to the extent our partner is obviously. dispatching and taking their share of unit production, the available production for us can fluctuate. So that's one impact. The GOMO project or Mercatucha project, those wells, because we have the facilities in place or will soon have the facilities in place, we do have the ability to add production from those as the projects get completed. With respect to the exploration wells that we just drilled, you know, the expectation, you know, we're in the final phases of getting the permit application for the pipeline done. There's an approval process associated with that and then a construction timing. So I don't think, you know, I think from an expectation perspective for additions from those discoveries to the extent they're natural gas,

those would be tied in more in the second half of next year so with production capacity at the unit still above processing capacity of the plant even with the expansion are there other small processing plant expansion possibilities yeah there is a so without getting into too much complexity there are some facility constraints there's

a high pressure and low pressure separation stream, our gas gets processed through the high pressure separation. So, you know, we technically couldn't take the full 600,000 cubic meters from the unit with the way it's structured. Okay.

Does the next processing plant expansion and movement towards 35 million per day depend on successful expansion into the 182-1 and 183-B-1 field?

Yeah so you know we're just looking to get the testing results from these two wells get our initial couple wells on at the GOMO and partly part of it is not just expanding the plant from a volume perspective what you need to do is you need to look at the gas composition of all the different projects, how much production you think will contribute from each one to properly design that expansion. So, you know, we're pretty close to that decision point, but I think we'll be in a better position closer to the end of the year.

Okay. It seems that you found gas and oil on the 183B1 well. Does this make testing more complicated or can you test all zones?

Yeah, the decision tree is certainly a little bit more complicated. Obviously, you know, the surgery is very prolific throughout the entire basin, so we're really excited about the lower part of the well that I reviewed there. You know, frankly, if we have a very good oil result in there, you know, we'll have to stack that up against all of our other projects, but that's something we could bring on production and cash flow relatively quickly and obviously would also be a focus for us. So Yes, we can test everything, but depending on the results, the decision tree going forward evolves.

And then does that change your strategy on focusing on natural gas?

No, I think to me it's just additive. We've got some highly strategic infrastructure in the basin. We've expanded it. The key objective, make sure that that's full day in, day out. We've got lots of projects, I think, to do that, but if we can add a leg of profitable oil production to that to complement it, then that's excellent for our stakeholders.

And if you test oil, can you keep producing?

Yeah, so the way that works is the formation testing regime that I think our shareholders have been used to in some of our past wells, for each of the different zones that we would test, we would have 72 hours to test those. And then we would make an application to do a long duration test, which would take at most, call it 60 days. And then we would be in a position to put the well on a long duration test, which could go up to six months. And in parallel, we'd be working to declare commerciality and be in a position that we could continue production. Obviously, there's a lot of work that has to be done. The other thing we need to consider is that our plan, just like at 182 to drill a follow-up, you know, we're fully expecting to drill a follow-up location off the 183B1 pad as well. So we just, it's not the biggest pad in the world, so we just have to be thinking about simultaneous operations and the timing of that. But with a good oil success, I think we can have that on production this year.

And we have a few questions that have come in on capital expenditure guidance, both for the third quarter and or second half of 2022, and then also any preliminary guidance on 2023. So maybe we can just walk through some of the projects on that.

Yes. So let's start back working backwards. Our 2023 program um really you know the key thing is we're going to get these wells tested um and then we'll be in a very good position i think to better refine our 2023 capital program but i think we've got probably more homes for reinvestment um than maybe what we even did six months ago which is really exciting and obviously we've got lots of cash flow that we're generating from from our core operations so i think it's a great position to be in um uh from the remainder of this year, we've really got two follow-up wells. So if we can just, the cutoff of this might be a tiny bit off, but as I mentioned, the two GOMO wells are probably in the early part of next year. So we've got the the 182 B2 and 182 C2 follow-up locations. You know, we drilled the last well actually under budget and quite efficiently, which was great, but it called in the $4 to $5 million range per well, so round that up to $10 million. We've got some testing of the 182 C1 location and potentially a more involved test because it's multi-zone at 183 B1. Depending on how many zones we test, those tests are anywhere between call it a million and $2 million each. The 182C one would probably be closer to the lower end of that and the 183B one would be closer to the higher end of it if we're testing all the zones. got i think most of the capital expenditures related to the facilities expansion or the facilities construction for the gomo completed um but there's a tiny bit of residual work there and then there's the completion and stimulation of the 197 well so once we get our permit to do that the pipeline will already be constructed you know that's that's up to up to maybe even three million dollars there we do have our share of the unit capital on the unit see well um but that's you know fairly modest um sorry allison's just reminding me also when we buy inventory for capital projects it shows up in capital and because we are experiencing obviously longer lead times we've always had a long-term planning focus But it's probably even extending further, but the net effect of that obviously is we're trying to do as good a job as possible planning. But it's also as part of the preparation for a growing capital program is you will see our inventory balances grow, which could be anywhere from a million to $2 million of equipment that are mostly tubulars that we put in inventory in advance of drilling.

Just going back to the gas sales agreement, does the 6% biannual ceiling increase we saw in August carry forward at 6%?

No, it gets adjusted for US CPI each redetermination period. So the next redetermination that happens in February of 2023 will be based on the second half of 2022 US inflation. So going forward, I think we've got... In the forecast that we showed there and in our reserve report, I think we have 3% inflation assumed for next year, and then we have 2% inflation assumed thereafter. Obviously, if the numbers are different than that, then the ceiling gets adjusted differently.

And on the unit, can you comment on who the unit operator is with the 50.9%?

Yes, I will. Sorry, and I just want to go back to that last question. To be clear, the 6% does carry forward. We retain the past inflation, and then the new inflation from the second half of this year will get added to that for the next price redetermination. It might not have been clear there. With respect to our partner, it's a local partner. Their name is Imatami. They're kind of an integrated company. They do fabrication for pulp and paper offshore oil. They've got a drilling rig. Their share of the gas gets sold to a thermal electric power plant that they built, which is different than our commercial solution, obviously. It's unique in that they only actually require gas when the thermal power project is being dispatched. So their demand profile is completely different than ours. That's a 25 year project that comes with it, sometimes long periods of time where the plant is not dispatched. And obviously, if you follow the news, Last year, a little over a year ago, Brazil was in a very dry situation. The reservoirs are actually quite full now. The primary source of electricity is hydroelectric. But when things get drier, then the thermal power plants get dispatched and their dispatch could potentially increase in the future.

Amy Nunez, Okay, and then we'll move into some more corporate type questions, do you still expect to be debt free by the end of the year and be paying off the remaining two and a half million of the credit facility.

Yeah, that's our current plan. We've got some work proceeds that are expected to come in here between now and the end of September, which would, you know, we've got lots of cash to do that. I think the one thing, there's not much left on it. I think, you know, with interest rates going up, actually the interest rate within our credit facility is probably, you know, more rational than how we felt about it maybe 12 months ago. But yeah, that's our core plan to get rid of that. Regardless, the facility maturity date is September of next year, so almost 13 months from now, basically.

With the highest cash flows we've seen in Q2 here, do you anticipate a dividend increase?

First of all, that's a decision the board needs to make, but what I have been guiding towards is, look, We've got a pretty robust capital program finally this year. We're really excited about the results. We want to get through the testing. We want to define what the development plans for these assets look like and what our capital needs are. Obviously, we've had a bit of a balance between debt and dividends. Once the debt's gone, that's another catalyst potentially where there's more cash available to stakeholders. But I think to date and with our plan through to the end of the year, we've been pretty close to what we've defined for our balanced model. And we'll be able to, I think, with more precision, define our next year's capital program. And these are things that we'll look at at the upcoming board meetings.

Yeah. And the next question I had here was on that capital allocation strategy and if you expect to change it going forward.

Yeah. Again, this is something we define probably five years ago before we even brought this project on production. But what we wanted to do is just say, look, we're going to approach this business in a more kind of responsible or disciplined way. I think back at that time, you saw companies reinvesting over 100% of cash flow and maybe not always in the most prudent way that was our opinion so we came up with this model we roughly said 50 to stakeholders 50 in in organic growth which you know is is much you know a lot of companies are now moving to this more balanced approach that we've been talking about for a long time obviously that's a big chunk to our stakeholders you know we think we can be there on a long-term basis but you know If we've got a bunch of compelling capital investments, we have to evaluate those as well. So let us get done the testing and we can define the program going forward. But that's our objective is to stick to that.

And we had one final question that just came in. How's your golf game? Steady, improving or need work? I don't know if that's for Corey or for me. Mine is improving, but I'll let Corey comment on his.

Yeah, I don't have to see who that is after this and call them back. No, it's not good. Which maybe is good for our shareholders because the golf game is really bad. So thank you for that and highlighting that.

And that is it for questions.

All right. Well, thank you, everyone, for participating. As always, Alison and I are both available for questions. Feel free to call us and we look forward to updating you and having our next call in three months time.