Alvopetro Energy Ltd. (ALV), an oil and gas exploration and production company, has reported a 49% increase in production and sales in July, with positive results from their Caburé project. During their recent earnings call, the company highlighted their increase in production, strong financials, and plans for future growth. They announced their goal to reach 3,000 barrels of oil equivalent per day and expect to maintain production levels throughout the year.
The company has a strong balance sheet with a funds flow of $7.9 million for the quarter and is focused on organic growth through the development of the Caburé and Murucututu assets. Alvopetro also announced a share repurchase program and plans to potentially grow dividends as earnings increase.
Key Takeaways
- Alvopetro reported a 49% increase in production and sales in July.
- The company plans to reach 3,000 barrels of oil equivalent per day, with a focus on the Murucututu project aiming for over 5 million cubic feet per day by 2025.
- Alvopetro has a strong balance sheet with a funds flow of $7.9 million in the most recent quarter.
- A share repurchase program has been announced, with plans to allocate excess cash flow to share repurchases.
- The company has a balanced capital allocation model, reinvesting in organic growth and returning funds to stakeholders.
- Dividends may be evaluated quarterly, with the potential for growth based on earnings.
Company Outlook
- Alvopetro is committed to increasing production from their Murucututu project to support their goal of 3,000 barrels of oil equivalent per day.
- The company plans to invest in capital expenditures, with expected results from these investments in the next quarter.
- Alvopetro aims to reach over 5 million cubic feet per day from Murucututu by 2025.
Bearish Highlights
- The company experienced a slight decrease in gas sales price due to currency devaluation.
- The ICC full review process is expected to be complex and could take multiple years.
Bullish Highlights
- Alvopetro reported strong operating netbacks and funds flow.
- The company has a clean balance sheet and strong free cash flow generation.
- There are plans for organic growth through the development of the Caburé and Murucututu assets.
Misses
- No specific misses were highlighted in the earnings call.
Q&A Highlights
- The company expects to maintain production levels for the rest of the year.
- New firm production levels will be evaluated for the next contract renewal.
- The development program includes drilling five wells starting in Q4 and continuing into 2025.
- The company intends to use the NCIB and expects approvals within the next couple of weeks.
- Excess funds will be allocated to share repurchases, with dividends evaluated quarterly.
Full transcript - Alvopetro Energy (ALV) Q2 2024:
Alison Howard: [Call starts abruptly] Good morning, everyone. Thank you for joining us this morning. Just a few administrative points before we start. We will be recording today's webcast and there will be a replay available on our website later on this afternoon. [Operator Instructions] We will be hosting a Q&A session at the end of our presentation. So you can use the Q&A button on your screen to submit any questions and we'll get to those at the end of the presentation. Alternatively, if you're dialing in, you can send any questions you have to social media at alvopetro.com and we will also get to those questions. And lastly, just a friendly reminder that we do go through various non-GAAP measures throughout this presentation as well as make various forward-looking statements. So please review all of the cautionary statements and other disclosures that you can find at the end of our presentation that's posted on our website.
Corey Ruttan: Thank you, Alison. So just to start with production here. So since we came on production from our Caburé project on July 5, 2020. I think we've posted some pretty good results here. Just a reminder, our first couple of quarters, we came on production roughly at our pre-commercialization expectation levels which were equal to our firm volumes within our Bahiagas contract and also equal to our share of unit -- our working interest share of unit production. For several quarters after that, our partner wasn't nominating for gas and we were able to sell all that access to the Bahiagas on a flexible or interruptible basis. So you saw some pretty significant production increases through this period of time. We also expanded our gas plant, our gas processing facility in the third quarter of 2022 and had an increase there as well. And then in the second quarter of last year, our partners started nominating for more gas and we also saw some demand impacts in the state of Bahia that resulted in lower nominations from Bahiagas than what we had seen previously. So we went through this period of time. And then last month, as we announced yesterday, we had a nice increase in the month of July. We agreed to review the pricing on just our flexible volumes within our contract on a monthly basis and the result was a 49% increase when you compare that to the 1,629 barrels of oil equivalent that we produced in the second quarter to the 2,432 barrels of oil equivalent that we produced and sold in the month of July. So our strategy continues to be adding more 100% working interest production from our Murucututu project. I think we've got some exciting results that we should be announcing here over the coming months and then Adrian will walk through that with you later in the presentation. But our objective is to be at our -- with the addition of some of those volumes to be approaching our near-term 3,000 barrels of oil equivalent per day goal. We talked about the redetermination on our last call. I think 1 or 2 days after that, we announced the result of our emergency arbitration proceeding as well. So just to recap for people though, we did have a positive result as a result of the redetermination process, it became effective on June 1, with our interest -- working interest in the unit increasing to just over 56%. And that transition of unit operatorship to Alvopetro is also underway. We have previously advised that our partner is disputing that. Like I said, right after our last call, we announced that we got an emergency arbitration order that grants the interim effectiveness of the expert decision until a long-form arbitration can be completed. And to be clear, our [indiscernible] does dictate that expert decisions and this redetermination process -- such as this redetermination process is to be binding. So we also, in our release yesterday, announced our latest semi-annual price update under our gas sales agreement. Just a reminder how this works. We've got a long-term gas sales agreement with Bahiagas. The prices are calculated based on 3 international benchmark prices. So you can see them in the various gray dash lines. This low one is U.S. Henry Hub gas prices. This upper one is U.K. NBP gas prices. And the middle one that you see here is Brent oil equivalent prices. So you blend those together, average them over a period of time and it calculates Alvopetro's price in the block. You can see we've been roughly at the ceiling. We do have a ceiling and a floor within the contract which is the green and the red, both of those escalate based on U.S. inflation. So we just announced our latest reset here. On a Brazilian real basis, the price was virtually unchanged from the last price that we saw. But because we have had some devaluation in the Brazilian currency, we did see a U.S. dollar-denominated slight decrease in our price to just under USD 11 per Mcf. And you can see we're just slightly below the ceiling price within our contract. And then if we use the forward strip or forward curves in the market as of yesterday which is to the right of this line for each of those 3 different benchmark prices, you see the calculated price that's just slightly below our ceiling here for the duration of this chart that you see.
Alison Howard: So just jumping into the results that we released yesterday, starting off with our operating netback. That is one of the non-GAAP measures that we look to that is basically our operating profitability for we expressed in a barrel of oil equivalent. And just as a reminder, we compute that. It's the realized sales price. Those are the numbers at the very top of the stacking bar chart and we deduct off the royalties in orange and production expenses in the gray bar and that gets us the operating netback which is the green bar there. So in the second quarter, we did see a reduction in our realized sales price down to just below $72 per boe. That was mainly due to a reduction in our effective U.S. dollar realized price on our natural gas sales. That went from $1,257 per Mcf in the first quarter to $11.83 in the second quarter. Royalties were relatively consistent this quarter with last quarter, effective royalty rate of about 2.7% on our realized price. Just as a reminder, our statutory royalty rate in Brazil is between 5.5% and 11%. But with royalties on natural gas, it's based on more of a raw unprocessed value of that natural gas. So it's closer to a Henry Hub equivalent that the royalties get paid on. So that results in a lower effective rate. And then on the production expenses side, we did have a reduction in volumes this quarter and a lot of our operating expenses are fixed in nature. But despite that, we did have a reduction of over $2 per boe compared to last quarter. It was about $351,000 [ph] lower than Q1 and that was mainly due to some historical tax credits that we were able to get this in Q2 to recognize in Q2. So overall, that reduced our operating expenses this quarter and results in lower cost per BOE. And that gave us a netback of $64.30 for the quarter. It's down about $1.86 from last quarter. Again, that's mostly due to the pricing still relative to our realized price, we're looking at a margin of 89%. And we went through this in past quarters, that's really top-tier operating netbacks when you compare it to other South American companies or companies operating in Canada and the U.S. And when we layer into that, we have a nice tax incentive in Brazil that really reduces our tax rate to about 15%. So our -- that helps us generate significant funds. So even in periods like this quarter where our production was down about 4% from last quarter. So moving on to funds flow. So again, this is one of the non-GAAP measures that we look at and it's basically cash flow from operating activities but before changes in working capital. So what we did see about a $600,000 decrease in our funds flow compared to Q1. Most of that was due to the lower sales volumes and lower realized prices. G&A was a little bit higher and then offsetting that was that lower production expenses that I referred to and lower current tax and so we ended the quarter with funds flow of $7.9 million. On the net income side, similarly, that was impacted as well by lower operating netback with the lower pricing and lower sales volumes in the period. But the biggest significant adjustment here on net income was foreign exchange losses. So any of the U.S. dollar-denominated liabilities of our Brazilian subsidiary, those results in foreign exchange on current exchange loss in the local books that gets picked up on our U.S. dollar statement. So we did see that the devaluation of the Brazilian real in -- from March 31 to June 30 increased losses in our Brazilian subsidiary on that. So foreign exchange losses were the biggest contributor there in that $2.2 million reduction in net income. Partially offsetting that was lower current tax which I already mentioned and then also lower deferred tax and depletion and depreciation. On the balance sheet side, we continue to have a very strong balance sheet. We -- just as a reminder, we are debt-free, we repaid our credit facility back in September of 2022. It was fully repaid. And so we ended the quarter with $14.7 million of working capital. And I think, of that, it's about $19.7 million of cash. So just going through our dividend history, we have been paying dividends since the third quarter of 2021. We paid every quarter at these varying amounts. This is just part of our long-standing balanced stakeholder return and reinvestment model. So to date, we paid USD 1.22 per share in dividends and that has amounted to just under USD 44 million. The Q2 dividend, we announced that in June, it was a paid already in July. It was consistent with our Q1 dividend of $0.09 per share and that was reduced relative to 2023, just with the lower production volumes we've seen to date or seen up to the end of Q2 anyway and then lower cash flows. But overall, that's a dividend yield of just over 10% at these current prices.
Corey Ruttan: All right. Thank you, Alison. So yes, this balanced capital allocation model that we talked about, this is something we introduced quite some time ago. The model is to basically take half of our cash flows and reinvest that in organic growth and take the other half and return it to stakeholders. So if you look at the chart on the left-hand side, this is -- since we came on production, all the different funds flow that we've generated by quarter or the black dots in the green line that you see here, most recently, the $7.9 million of funds flow that Alison referred to. And then each of the stack, so that's the cash inflows per quarter and they're all the stacking bars or the cash outflows on a quarterly basis, broken down by type. So you can see early on, virtually all the cash either went to building cash and working capital and/or repaying on an accelerated basis, our initial credit facility that we had which is in the green cross-hatching that you see here. We did do a share buyback in the third quarter of 2021. And we also introduced the dividend, as Alison mentioned, at that time. So those are the solid green bars. And then more recently, you've seen initially because we had prefunded all of our Caburé project, we didn't really have to be investing a lot of capital near the beginning. You have seen more of that recently and you'll see us ramp that up a little bit here in the second half of this year as well. If you look at it in total, since July, so this is now from the July 5, 2020, all the way through to the end of the second quarter of 2024, you can see we've spent, of the $147 million of cash flow or funds flow from operations that we've generated, 43% of that went to capital expenditures, 9% of it's gone towards building that cash and working capital position that Alison referred to. And then around 48% of it went out to stakeholders. We did announce yesterday a plan to complement our stakeholder return, portion of the pie here with a share purchase -- repurchase program. And our intent is to basically take any excess, if we take funds from operations, multiply that by 50% and then deduct off our dividends and our capital lease payments. And if there's an excess amount there, our intent is to allocate that to share repurchases. So if you do that for the first half of this year, we have excess available cash flow from that of $0.5 million. That's the initial allocation. And our expectation is that we can grow that based on results moving forward over the coming year here.
Adrian Audet: I'll just update you guys on the organic growth plan here. So just a reminder, we have an existing midstream infrastructure to sell up to 18 million standard cubic feet of gas with our existing transfer pipeline, our existing UPGN, our gas processing facility and the connection to the local gas distribution company which is Bahiagas. As Corey mentioned earlier in the presentation, we had positive redetermination results, increasing our working interest production from this Cabure or unit, increasing our production entitlement from 49% to 56.2% of the production capacity of that field. Currently, this year, we're going through the capital development program at the unit Caburé with additional wells and unit compression or field compression at that facility and that will enable us to continue our production levels to Bahiagas from the asset here. The other main asset that we're focused on get in 2024 is the Murucututu, so that's our 100% working interest asset just north of Caburé. We've got the existing infrastructure built to produce up to 7 million standard cubic feet of gas to sales from that asset with the transfer pipeline and end of [indiscernible] central processing facility at the 183-1 location. The -- that location also has the 183-A3 wellbore. And currently, we're going through recompletion operations at that location to recomplete the Caruaçu zones in both the 183-1 and the 183-A3 wellbores. And that work is currently ongoing. The benefit of that is both those wells are currently tied into our infrastructure. So as soon as we're done, the completion operations, they'll be immediately put on to production and sales. And we expect to see results of these capital investments in the next quarter here. Following this, we have a multiyear development opportunity in Murucututu with existing locations constructed for follow-up wells depending on the work we're doing here in this quarter. And as highlighted in the reserve, both reserve and the contingent prospective reserves report, we have a lot of growth and running room for the Murucututu asset. So we look forward to that.
Corey Ruttan: All right. Thank you, Adrian. So just in summary, I do strongly still believe that Alvopetro offers an attractive investment proposition, no matter what your focus is. I think you can see from the results, they speak for themselves. We benefit from very attractive gas prices, industry-leading operating netback tax. We've got a clean balance sheet and very strong free cash flow generation capacity. And all that together helps support our balanced stakeholder return model. For value investors, we're trading at about 1/3 of our 2P NAV. For yield investors, our dividend translates into over a 10% dividend yield at current prices with dividends paid quarterly in U.S. dollars. And then for growth investors, we've got an exciting organically funded capital program and certainly a significant amount of potential when you compare it to our existing market cap or enterprise value. And we've got, I think, some exciting results coming out over the next literally 30 days here. So with that, we'll turn it over to the question-and-answer period and I'll just quickly stop sharing the screen.
Alison Howard: Yes. So we have a few questions that have come in, both through Zoom (NASDAQ:ZM) and on social media. For the gas price for July and for the rest of the year for the volumes that are sold incremental to the term volumes under the contract, what gas price do you expect to achieve? And how much price sensitive demand are you seeing from Bahiagas?
Corey Ruttan: Well, that's the whole reason why we went through a phase where some of the demand impacts the Bahiagas we're seeing, were temporary and then it became clear that some of them were actually more permanent. So that was kind of an evolution. And I think some of the market is responding to that similarly to how we are responding. But overall, the price adjustments we're talking about are overly material but the production increase that we have seen is quite material. So we'll continue to review the situation monthly. I think more importantly, we've talked about this before but basically, what happened was Bahiagas projected a demand forecast out for 2 years and build up their gas supply as well as their transportation commitments for basically all of 2023 and 2024. So as we exit 2024, our expectation is that Bahiagas is going to adjust their overall portfolio so that it recalibrates things down to this new demand reality. And as a result, we wouldn't see the type of fluctuation that we've seen in the past.
Alison Howard: Where is production capacity at, at the moment? And when do you expect to reach the near-term goal of 18 million cubic feet a day?
Adrian Audet: Yes, the production capacity, I would say, is limited by our UPGN which is roughly 18 million cubic feet a day or 500 e3m3 a day. So we can easily sell up to that if we have the productive capacity at the fields. And part of our capital program right now is to increase the rates for Murucututu, so we try and achieve that goal. So...
Corey Ruttan: Yes, it's a little bit of a function of the amount of production that we're taking from the unit as well as the results on this upcoming activity. So I think we'll be in a better position to answer that in a month's time, hopefully.
Alison Howard: So we do have a few questions on Murucututu. Is the aim still to reach over 5 million cubic feet a day from Murucututu in 2025?
Corey Ruttan: Yes. So we're -- sorry, Adrian -- so the plan really is to take what we're doing with these recompletions and then apply the learnings from that to our capital program going forward. So we want to get those results in and then position ourselves to start executing our long-term development program. So certainly, directionally, we think that asset can still deliver on our longer-term objectives. The timing of that may shift a little bit based on when we start the drilling program. But I think we're really well positioned because we've got 3 drilling pads to drill multiple development wells from that are all pipeline connected. So we're uniquely positioned to quickly convert natural gas drilling successes into production and cash flow. And then as we develop that resource in the southern portion of our Murucututu project, we can get out in front of that and start to build with well pads and additional field pipelines to connect back to our 183-1 facility which has an initial capacity but it -- as Adrian mentioned, of about 7 million cubic feet a day. But based on results that can be easily expanded.
Alison Howard: So there was a follow-up question to that. You've already answered most of it but around the timing of drilling the new wells on Murucututu and the expected CapEx in the second half of this year and 2025. I think you've already answered that the new wells are dependent on the results of this program that we're undertaking right now as will be the CapEx for that would be dependent on that as well and the timing for that. For the second half of this year, the recompletions that we have planned here on 183-1 and 183-A3, that's at an estimated cost of roughly $3 million and that should mostly be in the third quarter. So just to round out that question. Another question on Murucututu. How are you developing? And are you permitted to frac?
Corey Ruttan: Yes. So we're in the phase of actually getting a development permit for the field license. There's a natural transition period out of the exploration phase and into the development phase. And our expectation and plan will be to use stimulation technology, that's our current plan as we develop the field.
Alison Howard: If the results of the 3 existing wells and the programs we have planned there on Murucututu are meaningful, will Alvopetro do a reserve update?
Corey Ruttan: Yes. I think practically speaking, by the time we get -- we'll get some initial results here, hopefully, by the end of August, we'll want -- we'll see a couple of months of that. It will be pretty close to our normal reserve update season anyway. So my guess is we would probably wait but...
Adrian Audet: Yes. Exactly.
Alison Howard: Okay. A little bit more on the production side, thoughts on why there was a jump in sales in July? And is it a trend? Any specific reason why Bahiagas nominated more?
Corey Ruttan: Yes, I touched on this through the presentation. It's pretty much entirely due to reviewing our flexible pricing on a monthly basis. We did the same for August. We expect production to be similar in August. And our hope is -- our expectation is that we can continue that through the rest of this year. And then with the annual contract renewal, we're evaluating new firm production levels that will help secure at least a nice higher base of production and then complement that as we add Murucututu production over the next 18 months.
Alison Howard: And are you providing specific production guidance for the second half of 2024, can we expect it to remain at July levels?
Corey Ruttan: Well, again, so we're kind of unique in that our production guidance is mostly a result of what's happening with our uptake of Bahiagas. So our current expectation is to stay at similar levels. But no, we don't typically provide quarterly production guidance.
Alison Howard: There's another question, where are you focusing your development program?
Adrian Audet: Yes, I think I'll take that. As I noted on the organic growth slide earlier, we've got a development program at the unit where we're drilling 5 wells. I think I mentioned we're going to start to drill those in Q4 of this year and it's going to go into 2025. We're developing that field with [indiscernible] compression that will be installed and commissioned in the fourth quarter. So that's one chunk of our development program. And then the other aspect is Murucutu which we've been talking about where we're focusing our efforts on these recompletions that we're doing right now, putting those wells online and taking the recompletion learnings that we're doing that to incorporate into the future development and drilling programs in 2025.
Alison Howard: Just moving to some corporate questions. How long do you expect the ICC full review to take?
Corey Ruttan: Yes, these are hard questions to answer because every process is different but I think this is sufficiently complex. Our -- based on the advice that we're getting is it's potentially a multiyear process.
Alison Howard: On the NCIB, there's a question, if we expect to actually use the NCIB this time, especially to reward longer time shareholders, long-term shareholders.
Corey Ruttan: Yes. Our intention is to be using this. We expect to get approvals, hopefully within the next couple of weeks. And we put set an initial budget and our expectation that we can certainly continue the results that production levels like we've seen in July would generate, I think we'll certainly be able to complement that -- the budget related to share repurchases moving forward.
Alison Howard: Will there be a priority to continue to grow the dividend where it was prior to the cut? Can we expect consistent annual dividend growth as earnings grow?
Corey Ruttan: Yes. No, that's a good question. It's something that we talk about at the board level every quarter. I think I would say -- and obviously, this is subject to the Board decision every quarter. But certainly, in the near term, the plan is to take the excess above that base dividend and allocate it to share repurchases. And then based on results, we'll evaluate that mix between additional dividends or additional share repurchases on a -- really on a quarterly basis.
Alison Howard: And we have no further questions at this time.
Corey Ruttan: All right. Well, I want to thank everyone for joining again today. We look forward to updating you over the next month and certainly see you again on the next quarterly call. If you have any questions, feel free to reach out to any one of us. And thank you for all the support.
Alison Howard: Thanks, everyone.
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