Categories Earnings Call Transcripts, Energy

Alvopetro Energy Ltd (ALV) Q1 2022 Earnings Call Transcript

ALV Earnings Call - Final Transcript

Alvopetro Energy Ltd  ( TSX: ALV) Q1 2022 earnings call dated May. 13, 2022

Corporate Participants:

Corey C. Ruttan — President, Chief Executive Officer and Director

Alison Howard — Chief Financial Officer

Presentation:

Corey C. Ruttan — President, Chief Executive Officer and Director

Good morning. Thanks for joining us today for our Q1 2022 Results Webcast. I’m Corey Ruttan, President and CEO, and I’m joined by Alison Howard, our Chief Financial Officer.

As everyone knows, a replay of the webcast will be available on our website shortly after the call. All attendees are in listen-only mode for the duration of the webcast. Following the presentation, we will have a Q&A session using Zoom’s built-in Q&A feature. So if you’d like to ask a question, please click on the Q&A button on the bottom of your screen, and you can type in your questions at any time during the event. For those of you who are dialing in, you can also submit your questions by e-mail to social media at alvopetro.com.

So we’ll let everyone read the cautionary statements at their leisure. They’re also within our MD&A and our financial statements.

So just to start off, we continue to post pretty strong production results. I certainly think they’re well ahead of recommercialization expectations. We have our strongest quarter yet in the first quarter at 2,501 barrels of oil equivalent per day. That was up 15% year-over-year and up 3% quarter-over-quarter. April was a similarly strong month for us, just shy of 2,500 barrels of oil equivalent per day. So this is the same chart that we showed on our quarterly call last quarter. It shows the gas pricing mechanism within our gas sales agreement. The three gray dashed lines that you see here are the three different international benchmark prices that are used within our price calculation being Henry Hub, Brent oil equivalent and UK NBP gas prices. You can see the dark black line is Alvopetro’s calculated price. And you can see we had almost a 50% increase on the February 1 price redetermination. One of the other things you can see is because the Brazilian currency is appreciated since that redetermination happened, we’ve actually been above the contractual ceiling. So the ceiling is in green. It escalates based on US inflation. But because of that appreciation in the currency, you can see a gap here through the first quarter and it’s actually forecasted to continue based on our current foreign exchange forecast.

The other thing to note here is, to the left of the red dash line is the history and to the right of the red dash line is the forecast. So what we’ve done is we’ve updated this for the most recent strip pricing that we had for all three of those benchmark prices. We’ve then calculated what the price formula within our contracts fits out and that’s the blue line that you see here. But because of the ceiling, you can see the dark black line stays on the ceiling through the entire term of this graph here. So when you contrast that to what we showed two months ago — compared to the price forecast back two months ago, this period of time that we stay at the ceiling actually extends for two years longer. And if you compare it to the price forecast that were used by GLJ in our reserve evaluation, it actually extends it for a period of over three years longer than that forecast. And also, this gap between the blue line and the black line is bigger than what we showed last time. So what that tells you is this is kind of the amount that the combination of these three benchmark prices could decline by before we would actually realize a reduction in our gas sales price.

So with that, I’ll turn it over to Alison.

Alison Howard — Chief Financial Officer

Thanks, Corey, and good morning, everyone. So with those strong gas prices that Corey just referred to as of February 1, so two months in the first quarter, our operating netback increased significantly close over $17 per barrel of oil equivalent from Q4. So the operating netback is our operating profitability per unit of production and we use barrel of oil equivalent and we went to just under $54 which is the green bar that you see there in Q1 because of our realized sales price increased to $62 compared to $44 in Q4. So that’s a significant increase. And recall, this is only two months of production at that higher gas sales price. So should see an even further improvement in Q2 going forward when we have a full quarter at those higher prices.

Our production expenses, we’ve maintained below $4 since we came on production in July 2020. So those overall, most of our production expenses are fixed in nature. So we’re able to keep those costs low, and royalties have been consistent as well. So overall, very high operating netback margins, 87% being the highest one to-date here and overall since inception over 80%. I think it’s over 82%, actually, since inception. And on the royalty front, we talked about it in our MD&A, but we did get approval for a reduction in our government royalty rate effective May 1. So that should help improve our results going forward as well.

So then moving on with those strong operating netbacks, we have record funds flow from operations this quarter, increasing to $10.9 million, which is great, up $4.4 million from last quarter and that’s basically all due to that increase in our realized price because our production, we’ve been able to maintain close or right around this 2,500 barrels of oil equivalent per day, and that’s at the higher price and then a little bit lower G&A compared to Q4 was very strong funds flow from operations this quarter.

Similarly, net income increased as a result of those higher funds flow from operations. And then in addition, recall that we continue to be subject to foreign exchange fluctuations. And this quarter was a foreign exchange gain of $5 million compared to a loss of $0.9 million. So a swing of close to $6 million in our net income. Most of that is on our inter-company loan balances. I went into this a little bit last quarter. But for accounting purposes, we are required to recognize foreign exchange gains and losses on inter-company amounts, even though those limit the balances themselves or eliminated on consolidation. So we’ll continue to see fluctuations in net income for foreign exchange. But most of that, if you look at our statement of cash flow is adjusted in the statement of cash flows. So it’s all really mostly non-cash foreign exchange. And then those were significant increases in our net income and then with the increased funds flow and then that foreign exchange gain in the period, our deferred tax was higher this period, which caused a bit of a reduction. But overall, net income increased $8.5 million compared to last quarter. And again, record net income.

And then moving on with the strong cash flows and our continued strong production levels well ahead of expectations, our working capital, which is our current assets less current liabilities and shown in that green bar there has increased steadily since July 2020. And the orange line is our credit facility. And you can see starting in Q3 2021, our working capital actually started exceeding our credit facility balance and that gap has grown. And as of Q1, our working capital was $12.3 million and our credit facility balance of $5 million, so $7.3 million excess there. And with the strong cash positions and strong working capital, we did notify our lender that we would repay an additional $2.5 million as it’s effective next week. So that’s actually half of our balance that was outstanding at March 31 and it leaves us with an outstanding balance of $2.5 million and at these cash flow levels, that’s well under one month of cash flow.

Corey C. Ruttan — President, Chief Executive Officer and Director

Great. Thank you, Alison. So obviously, the record production and the higher gas prices made Q1 our strongest quarter to-date. Our funds flow from operations, as Alison highlighted, increased 68% quarter-over-quarter and 129% year-over-year, up to close to $11 million in the first quarter alone. You can see here on this graph, just kind of where we’ve been allocating our capital resources since we came on production. You can see during the first year of operations, we had a big chunk allocated towards repaying the credit facility, as Alison highlighted, relatively low amounts in yellow related to capital expenditures. Because of the strong results, we were able to start our dividend program about six months ahead of original plan starting in the third quarter. You can see that in the green wedges here, actually increased that this quarter by 33% up to $0.08 per share. And then in the first quarter of 2022, you can see us — the commencement of our 2022 capital program. So certainly, more allocation to that, and I’ll walk through kind of the early impacts of that.

To put this in perspective, the first seven quarters of production, so since July 5, we came on production from our Cabure project. You can see we’ve had funds flow from operations in excess of $43 million, close to a quarter of that’s gone to capital investments a little over a quarter of it to credit facility and interest payments and about 16% of that to dividends. So obviously, we’re very focused on our next phase of growth. To be clear, our near-term objective is to get to 18-plus million cubic feet a day. That would represent a 30% increase from where we are today. Our longer-term target is to double the size of our plant and be roughly 50% of the city gate that sits right at our gas plant location. The growth is planned to come from a combination of areas. So first of all, our gas plant expansion is on-track to add that capacity. We expect to be able to produce and sell at least 18 million cubic feet a day, starting the middle part of this year.

Our Cabure asset continues to perform very well. Along with our partner there, we do plan to drill one additional well targeting both some shallow development potential, but more importantly, some exciting exploration potential on the Western side of the fault, targeting the same reservoirs we’re producing from today. So that could further extend the productive capability of the Cabure field. And then we’ve got our 100% projects that we’re investing in our 2022 capital program. We just finished drilling the first of two conventional exploration wells and announced a success based on logs there at the 182-C1 location. The rig is now on the 183-B1 location and we should start drilling that shortly. As you recall, GLJ had independently assessed both of these prospects at 4.6 million and 5.9 million barrels of oil prospective resource, respectively, with 47% and 44% chances of success. Our plan here with the successes would be to tie these in directly to our gas plant directly to the South, so that it will involve building a new pipeline.

And then lastly, our Murucututu/Gomo project, it sits immediately North of our Cabure asset. I’ll walk you through what the capital plan looks like here. But we’re I think, well positioned to implement a broader scale our Gomo development plan and we’re very excited about our 2022 capital program. So just to talk about our 182-C1 results, so we reached a total depth here in April. This was a multi-zone prospect, so we were targeting the Agua Grande and Sergi formations. What we encountered you can see on the well logs here on the left is a very continuous, very thick 36-meter Agua Grande sand. About 25 meters of that you can see on the right-hand side, meets our net pay cutoff thresholds, but it is a nice fit continuous sand that we’ve got here. The well log show average water saturations of about 34% and average porosity of 8.2%.

One of the things that did happen is as we drilled through the Agua Grande almost immediately thereafter, we crossed over the main bounding fault on the Eastern side of the prospect and we ended up not encountering the Sergi formation, which was the second target in this well. What happens is after we get our well logs we go back and recalibrate our seismic and all the time depth relationships. And once you have a well result, you can much better correlate the individual seismic sequences and the seismic character to the actual reservoirs that you validate based on the log and we can also better image the fault. So what our plan here is to drill a follow-up location further to the East and it’s kind of multi-purpose. So the first objective is to help better define the lateral extent of our Agua Grande discovery. We don’t see any water lag or anything on the log. So we’ll need to drill further to the East to really test the limits of this, but it’s pretty exciting. The other thing that we think can happen because we’re very close to the fault, what can sometimes happen as you get these cementation effects that can occur close to the fault. So we think as we move further away from the fault to the East that we’ll get more typical Agua Grande porosity that we see in the analog fields all around us. And then the third objective, obviously, is we still expect to encounter the Sergi formation in that more Easterly location when we drill the follow-up well. So obviously, pretty exciting to drill our first exploration well and have a success here. We look forward to testing the well later this quarter.

So moving on to the 183-B1 location like I said, the rig is on location here now. This is another 100% working interest prospect. It sits immediately to the Northeast of the 182-C1 locations. So you can see the fault block that we drilled into for the 182-C1. This is the fault block immediately to the East that you see here and on trend with the analog Biriba. Again, it’s a multi-zone pre-rift prospect, targeting the same Agua Grande and Sergi sands. On the cross-section on the left here, you can see the prospective reservoir sand stacked up against basement on the other side of the bounding fault. Again, this was evaluated by GLJ at 5.9 million barrels of oil equivalent, best estimate prospective resource with a 44% transit discovery.

So moving on to our Gomo/Murucututu project again, the Cabure field sits within this blue outline here. This was our original pipeline from Cabure, flowing to the West to our gas plant location. We’ve completed the construction of the pipeline up to the 183-1 location and we’re in the final phases of constructing the service production battery and facilities. We expect to be able to have that well on production here later this quarter. Then the next step will be to complete the tie-in of the 197-1 well, stimulate that well and then tie that in. We are waiting on permits to do that, but we’re lined up to execute that plan very quickly or immediately after receipt of the permits. And then the next step will be to drill the first two fit-for-purpose Gomo development wells off of these pads. The 2022 capital program that you see here targets the development of our 2P reserves. So on the production chart here it’s the lower lightest green color, on the capital chart on the bottom right. It’s the capital that we’ve allocated in the reserve report in 2022.

We then have a multiyear development plan here targeting the contingent and prospective resource that sits to the North. And you can see on an unrisked best estimate basis with success here, this asset alone has the potential of contributing up to 20 million cubic feet a day for us. So we’re pretty excited about having all this infrastructure in place and starting to drill wells here later this year as well.

Just to put this on again chart to give you a sense, the 182-C1 prospect, obviously, drilled, test that later this quarter. The 183-B1 location we’re getting ready to drill that right away. We’ll then move the rig back to the 182-C1 location to drill the follow-up well. During that same period of time, we expect our joint unit well to be drilled with our partner here. On the Murucututu project, like I said, we’re very close to having a 183-1 well tied in. And then subject to permitting, the rest of this activity that I talked about will follow through the rest of this year because that’s all pipeline connected, we can bring this production on relatively quickly. You can see that highlighted by the green flames here because we have a pipeline to build for the two exploration prospects, the production as actually wouldn’t come until 2023. And then the last part of this is just our gas plant expansion is on track for the middle part of this year, where we’ll have capacity of at least 18 million cubic feet a day available to us.

So just in summary, we continue to think Alvopetro offers an attractive investment proposition, no matter what your investing focus is. I think we’ve highlighted that we’re continuing to deliver results well ahead of expectations. Q1 was obviously a new record for production and cash flow for us. Our gas prices are obviously very attractive but Alison also walked through our operating netback margins. Those are industry-leading margins up to 87% in the first quarter. Our balance sheet continues to get even stronger. We’re almost debt-free and certainly on a net cash position in an extremely good position. That helps underpin our balanced kind of reinvestment and stakeholder return model that we’ve talked about for some time, where going forward, we’re looking to basically allocate half of our cash flows to organic growth and half of our cash flows in returns to stakeholders.

If you look at it from a value perspective, we’re trading at less than half of our 2P asset value and that’s before considering our most recent exploration success and any of the potential associated with that 2022 capital program that we reviewed. We’re also trading at about 3 times annualized funds flow from operations. So certainly, I think that we’re extremely attractively valued right now for yield investors, obviously, delivering a dividend yield over 7.5%, paying dividends quarterly paid in US dollars. And then for growth investors, obviously, I think we’ve got a very exciting 2022 capital program, significant near-term catalysts, especially when you consider the potential value relative to our current market capitalization.

So with that, I think we’re ready for the question-and-answer period. Before we get into that, just a reminder for those on the webcast, you can submit your question by hitting the Q&A button within Zoom.

Questions and Answers:

Alison Howard — Chief Financial Officer

Okay. Great. I’ll start with a few questions. Maybe we’ll start with the 182-C1 well, which was the well that we just drilled. Were the law calculations and net pay on 182-C1 comparable to other wells producing in that formation.

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So the thickness was actually probably at the very high end of the range that we would have expected. I would say the porosity is certainly lower than what we expected, but still, especially for gas within a good range and I think on a combined basis, certainly within our range of expectations for the Agua Grande. And I think like I highlighted, we still expect to also encounter the Sergi. Just to reiterate, I do think as we move further east from the fault that we’re going to get the more typical Agua Grande porosity that’s seen in the analogous pools to the northeast and northwest of us.

Alison Howard — Chief Financial Officer

And when do you anticipate completion work on 182-C1 to begin?

Corey C. Ruttan — President, Chief Executive Officer and Director

So we’re just in the final phases of contracting, but we do expect to have that work done later this quarter.

Alison Howard — Chief Financial Officer

Is it possible to use the 182-C1 well as a producer or do you need to drill development wells before bringing this field on production?

Corey C. Ruttan — President, Chief Executive Officer and Director

Well, we need to test it first. But yes, no, it can be a producer because we have a pipeline, that project between permitting and constructions is roughly a year between now and when the pipeline is committed or completed, we can drill a follow-up delineation and development wells and bring on hopefully a chunky production base, but step one, we need to test the well.

Alison Howard — Chief Financial Officer

And is the follow-up well on Block 182 an appraisal or is there another interval you’re now chasing?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So again, just to kind of reiterate what we’ve reviewed on that slide is it’s kind of — we’re drilling that for three reasons. Because we’ve got what looks like gas saturation from top to bottom, which is fantastic, it doesn’t really constrain the limits of what we see there. So to really understand how big the Agua Grande formation could be, we have to drill further to the east and further down depth to see how far away the hydrocarbon column actually extend. So that’s the first objective.

The second objective is to target the better porosity that we would normally see in the Agua Grande as we move further away from the fault. And then the third objective, which gets to your question is, yes, we absolutely still expect to encounter the Sergi formation and that’s why we need to drill further to these because we crossed the fault right below the Agua Grande formation. If we just move over, we’ll encounter the Sergi sands on the eastern side of the fault.

Alison Howard — Chief Financial Officer

And has the success at 182-C1 derisks the chance of success at your second exploration well on Block 183, which is our 183-B1 well?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. Certainly, I feel great about it. But I think technically, they’re all independent prospects. Part of the reason GLJ assigned 44% and 47% chance of success in this area is we do have analog tools that show that these faults have good ceiling capacity. We talked about that before we drilled the well. I think this just adds one more data point to prove that these faults have good sealing capacity. But technically, it’s a different fault. It’s very close, but technically still has those typical type of exploration risk associated with it.

Alison Howard — Chief Financial Officer

And can you review your drilling plants after 183-B1?

Corey C. Ruttan — President, Chief Executive Officer and Director

So yeah, we might have answered a couple of these questions as we went through, but I think this slide does a good job of walking through the catalyst and the drilling timing. Obviously, these things are always a little bit in flux and the Murucututu program, in particular here, we do have some permits that we think are in the final phases of getting, but the timing or sequencing is drilling the 183-B1 well next, the rigs on location, go back to the 182-C1 pad and drill the follow-up well, which is we’re calling 182-C2. So that’s the well to follow-up on the recent exploration success in the Eastern location. We then moved that rig to our Murucututu project, drilled the first of two development wells, fit-for-purpose development wells into our Gomo Murucututu asset here. The unit well will be drilled with a different rigs, will be happening in parallel with this other activity is our expectation.

Alison Howard — Chief Financial Officer

Okay. So switching gears a little bit, how is the upgrade to the gas processing facility coming along? Is it coming in on time?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. I think within seven to 10 days of expectation, it’s roughly on-time. So we’ll have some commissioning work. So we’re preparing the production facilities in May here for receivable of vessels that will be received later in June, so that we’ll be able to very quickly tie those in and turn the extra capacity on in July. There will be a short commissioning period at that time as well, but we expect a pretty quick ramp-up right up to the 18-plus million cubic feet a day of capacity.

Alison Howard — Chief Financial Officer

And is the 183-1 well on Murucututu tied into the pipeline and producing?

Corey C. Ruttan — President, Chief Executive Officer and Director

So the 183-1 well is tied in, that pipeline is complete. We’re just in the final phases of the production facility being constructed. So that’s the last step. Once that’s done, we’re ready to turn the well on production. So we expect to have that to happen here by the end of this quarter.

Alison Howard — Chief Financial Officer

Okay. And then shifting to some more —

Corey C. Ruttan — President, Chief Executive Officer and Director

Sorry, maybe just one other point to make here. The MURS-1 location that we have located here, this location would actually be drilled off that same service production lease. So when we drill that, it would be immediately tied into the EPF. The 197-1 well involves stimulating the well and building another roughly two kilometer pipeline. Once that’s done, that pipeline route is right on the MURS-1 location. So that’s why all of these we’re expecting to be able to — when we complete the capital activity fairly quickly turn them on production.

Alison Howard — Chief Financial Officer

Okay. And then maybe switching to some financial-related questions. Production expense per BOE increased a bit versus the previous quarter. What are the causes behind the increase? And what are your expectations for future quarters? I can take that one if it’s good.

Yeah. Our production expenses did increase marginally compared to Q1 2021 and Q4 2021. Part of that is most of our costs are fixed in nature, but with respect to our share of production costs from the unit, where we have a 49% working interest that’s based on our share of production allocations and we actually took 100% of the gas production from the unit in Q1 2022 compared to only 81% in Q1 2021. So that’s part of it. We do pay some additional fees right now for capacity above the nameplate processing capacity at the UPGN. When we complete this facility expansion that Enerflex is working on right now, that will shift to a capital lease, so it will actually come out of our operating expense. But that’s part of the reason for the increase as well.

And then lastly, the foreign exchange rates, the Brazil currency the reais improved on average relative to both Q4 and Q1, about 6% and 5%, respectively. So that causes our US dollar equivalent prices to go up a little bit. Going forward, I think we’re still targeting to be in that $4 per BOE range at these production levels will be impacted a little bit by foreign exchange, obviously, and then whether or not our partner takes their share of the gas. But overall, that’s our target is $4 going forward. And again, reiterating on our netback, this was only two months at this higher price. So we are expecting to see an improvement in our netback in Q2, for example, potentially over $60 per BOE in our netbacks just with two months at this higher price, assuming we’ll keep these production costs where they are and with that royalty amendment we discussed previously, which is actually the next question was asking about the royalty rates and —

Corey C. Ruttan — President, Chief Executive Officer and Director

But just to be clear, sorry, we’re talking about a $0.16 or $0.17 increase?

Alison Howard — Chief Financial Officer

Yeah, still very low. But yes, a marginal increase, but still very low. And then, yes, again, our royalty, we did get that royalty amendment. That was another question, we do have that effective for me production going forward.

Sorry, just let me give me one second here. With debt almost repaid free cash flow rising and the dividend already increased sharply, when will the Board start to consider a share repurchase program?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So I guess the way we look at this, like I said, our plan, we’ve talked about this for a long time. I think there’s a lot of companies out there doing it now. But before we even came on production, we said, look, take roughly half of our cash flows, reinvest that in organic growth, the other half to stakeholders. And obviously, I pointed out, our first priority was to repay the project financing loan. That’s almost complete. So I think once that’s complete, it sets a stage more for that discussion. So obviously, the bucket that’s allocated to stakeholders, with the debt stakeholder gone, the biggest stakeholder remaining is our shareholders. And then how we allocate that capital to shareholders, whether it’s dividends or buybacks, that’s a decision the Board will have to make in coming quarters. So we’re certainly not committing to that, but it’s obviously another tool in the tool kit that we can use to deliver returns to stakeholders.

Alison Howard — Chief Financial Officer

Another question here. What are your expectations with regards to cash tax payments this year?

I’ll take that one, yeah. Obviously, our cash tax is very low, consistent with Q4, but we had a large increase in our funds flow from operations. And that’s due to — we are eligible for the SUDENE benefit in Brazil. And then in addition, exploration costs are deductible and computing current tax, so that we benefit from a lower current tax. We don’t provide guidance, but overall, we are expecting current tax to increase in the future, but still be very low, I think, relative to most jurisdictions with the benefit of the SUDENE 15% tax rate that we benefit from right now. And obviously, we have tax pools, etc. So we’re always managing that to keep our current tax as low as possible. But yeah, we do expect that there will be — we will see a bit of an increase later this year and into next year.

The next question is what is the impact on cost inflation globally and service availability in terms of your exploration and development plans?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So I think one of the things about operating internationally is we’ve always had to manage projects with reasonably long durations, good planning. Obviously, those are keys to success. Things like you’re hearing this everywhere like tubulars for drilling wells, etc, the lead times are certainly longer and those are just things that we have on our [Indecipherable] chart probably earlier than we might have otherwise. But I think we’re well equipped to adapt to those things. We are seeing some certainly cost inflation and inflation in Brazil is above 10%, so that will get reflected in kind of the overall labor environment in Brazil. We obviously have a foreign currency effect that impacts that as well.

Alison Howard — Chief Financial Officer

And then what are your views on the state of the energy M&A market in Brazil?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So far, the energy M&A market has been dominated by Petrobras divesting of it virtually its entire onshore upstream inventory of assets. They’ve been in very large clusters that was recently announced one of the other and final cluster within our basin. Just looks like it’s in the process of being sold for $1.4 billion. So the good news is the industry is opening up. Petrobras’ influence on our sector is continuing to reduce. And I think longer term, that’s going to continue to open the door for more of that type of activity. Obviously, for us, if we can add shareholder value organically from the capital that we’re spending this year and leverage off the strategic infrastructure that we’ve got in place, we can add a lot of value for shareholders with success there.

Alison Howard — Chief Financial Officer

Just going back to 182-C1 and the discovery there. What is the length of that pipeline to connect to your existing gas processing facility and do you have any estimates of cost?

Corey C. Ruttan — President, Chief Executive Officer and Director

From the 182-C1?

Alison Howard — Chief Financial Officer

Yes.

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. So it will depend that happens with 183-B1 as well. If we go all the way to that location, it’s closer to 15 kilometers, it’s about 13 kilometers from the existing discovery that we’ve got. The answer to the capital cost will depend on how big the diameter of the pipeline is. But if we use kind of our Cabure experience, it’s in the probably — on the bigger end of the expectations for pipeline diameter, it’s probably closer to $4 million to $5 million.

Alison Howard — Chief Financial Officer

And I think our last question is how open is the gas utility to buy more gas from Alvopetro, i.e., past 18 million cubic feet a day?

Corey C. Ruttan — President, Chief Executive Officer and Director

Yeah. From everything they’ve told us, they would be pleased to take as much gas as possible. Like keep in mind, the marginal gas molecule that’s being consumed in Brazil has to be imported with LNG. And you saw the NBP prices, which is maybe a bit of a proxy for LNG, but landed LNG prices are probably double what our price is. So there’s a high amount of interest in us increasing our production.

Alison Howard — Chief Financial Officer

And there are no further questions at this time.

Corey C. Ruttan — President, Chief Executive Officer and Director

All right. Well, a very exciting quarter for us. Thank you to everyone for joining and look forward to updating you in three months’ time. If you have questions in the meantime, don’t hesitate calling Alison or myself and thank you again for all your support.

Alison Howard — Chief Financial Officer

Yes. Thanks everyone.

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