Alvopetro Energy Ltd. (OTCQX:ALVOF) Q3 2023 Earnings Conference Call November 9, 2023 11:00 AM ET
Corey Ruttan – President and CEO
Alison Howard – CFO
Adrian Audet – VP, Asset Management
Conference Call Participants
All right. Good morning. Thank you to everyone for joining us again today for our Q3 2023 Results Webcast. I’m Corey Ruttan, President and CEO. I’m joined by Alison Howard, our CFO; and Adrian Audet, our VP, Asset Management.
Turn it over…
Good morning, everyone. Thanks for joining. Just before we begin, a couple of administrative points. We will be recording today’s webcast, and there will be a replay on our website shortly after the call today. [Operator Instructions] We will have a Q&A session at the end of the presentation.
[Operator Instructions] Lastly, we will be going through some non-GAAP measures, and some forward-looking statements will be made in this presentation today. So just please, when you get a chance, read through our cautionary statements and other disclosure. Those are at the end of our corporate presentation, which is on our website.
And with that, I’ll turn it over to Corey.
All right. Thank you, Alison.
So our production in the third quarter was just shy of 1,700 barrels of oil equivalent per day. That was previously announced. It was impacted by the temporary demand decrease that we saw in the state of Bahia in the month of September.
You can see in October that’s reversed. We posted production of 1,839 barrels of oil equivalent per day in October, and that’s continued to be strong in November. Our strategy, we’ll focus on this later, is to really focus on adding 100% working interest in natural gas production from our near-term capital projects so that we can maximize the throughput through our gas plant and ultimately, as we move towards our near-term goal of above 3,000 barrels of oil equivalent per day. Our — just an update on our gas sales agreement based on some more recent futures pricing in the market. Just a reminder to everyone, our natural gas sales contract gets — the price gets reset twice a year, so every February 1 and August 1.
The price is calculated based on three international benchmark prices. So left of this red dotted line is the historical pricing, and to the right is the future projected period. The three different benchmark prices are in the gray dashed lines that you see here being U.S. Henry Hub natural gas prices, Brent oil equivalent prices and U.K. NBP prices.
Those get blended together, and it calculates our natural gas price, which is the dark black line, which is also subject to a floor and a ceiling within our contract. So that’s the red and the green lines, respectively. You can see they’re slowly ticking up here because they’re indexed to U.S. inflation. So what you see here is based on the futures pricing as of November 7 for those three commodities, we would expect to stay at the ceiling within our contract for the foreseeable future here.
So moving on to results from Q3 and specifically our operating netback, which just a reminder, is our net operating income expressed on a per barrel of oil equivalent basis. So to calculate that, we start with our realized price, which you can see at the very top of the chart there. So we were just under USD 79 per BOE in Q3, and that’s including our realized gas price of just over $13 per Mcf.
And then with condensate sales at a premium to Brent, we were able to see just over — or just under $1.50 increase from Q2 to $79. And we subtract off our royalties, which are orange, and our operating expenses, which are gray — in the gray bar there, to determine our operating netback, which was just over $70 per BOE, which is a record for Alvopetro.
So on the royalty side, we do pay royalties between — generally between 8.5% — around 8.5% plus some [ gross-overriding ] royalties. But for natural gas, our royalties are based on a value which is more tied to Henry Hub, like the raw unprocessed natural gas. So with Henry Hub pricing coming down this year, our royalty rate as a percentage of sales has come down. So in the quarter, it was $2, which was about 2.6% of that realized sales price. Our operating expenses, we did have lower production this quarter.
A large portion of our operating expenses are fixed in nature. So our operating expense per BOE did go up. But still, we were able to generate record netbacks of over $70. And when you compare that to our realized price of $79, we’re looking at a profit margin there — a netback margin of 89%, which is really best-in-class. And we like to show this slide here next.
So for any of Latin American producers and North American natural gas weighted producers that have released Q3, we compare our netback. Similar to past quarters when we’ve shown this, we’re at 89% netback margin compared to an average of 61%. So around 45% higher than these peers. And this is all before income tax. And just recall that we benefit from a low income tax rate on our natural gas profits in Brazil due to the SUDENE tax incentive that we’re eligible for until 2030, and that’s 15%.
So some of these other operators will be in the 30%, 40% range. So on an after-tax basis, it just shows the value of this production. And if we move on to our funds flow from operations, which is after tax, we did see a bit of a decrease, $1.4 million from last quarter due to that reduction in sales volumes, but still at USD 9.6 million, that’s very strong funds flow in the quarter. Similarly, net income, also impacted due to that reduction in our funds flow. And then also, there was a swing in our foreign exchange.
We did have a loss in Q3 compared to a gain in Q2 of foreign exchange. Recall that most of that is on our intercompany loans, and it’s all noncash, but it’s an accounting thing that we have to present on our income statement. So with the reduction in our operating netback and that change in FX, that overall loss in the period, offset by some reduction in taxes, we did see a decrease in net income of $4 million this quarter. Going to the balance sheet side. Just recall that we did pay all of our debt off just over a year ago now.
So we are debt free. So no debt on our balance sheet and strong working capital that we did see a bit of a decrease from June of over $6 million from June 30. That was — we did have some capital expenditures in the period and then lower funds flow, but still very strong financial position and still well positioned to execute on our long-term plan.
All right. Thank you, Alison.
Just to recap on our dividend track record here. We did introduce that back in the third quarter of 2021. You can see it was increased three separate times. And for the last three quarters, we’ve been paying USD 0.14 per quarter. Translates into a yield at current share prices of about 9%. And you can see we’ve already returned USD 0.90 to shareholders since we came on production from our key project.
So just talk about our disciplined capital allocation model. If you recall, we established this quite a long time ago, even before we came on production, where we’re roughly looking at targeting to reinvest about half of our cash flows in organic growth through capital expenditures and take the other half and return that to stakeholders in its various forms.
So this graph kind of shows what that looks like. The green line with the black dots here represents all the cash inflows, so the cash flow from operations that Alison walked through earlier. Again, in the third quarter, that was $9.6 million. Each of the stacking bar charts represents the cash flows — or cash outflows from each quarter.
So you can see at the beginning — just a reminder, as Alison noted, we took a lot of those cash flows at the beginning and really focused those on repaying our project financing loan that we got in place and paying that off in a rapid fashion.
That’s the green cross-hatching here. The dark solid green at the top of these bars is the dividend that I reviewed. Again, it was introduced in the third quarter of 2021. And then you can see more recently in yellow that we’ve now started to focus on the capital investment side of our business. And we’ll talk a little bit about what that looks like and what that looks like going forward.
In total, since we came on production in the third quarter of 2020, you can see how this has been split. So in total, we’ve now had funds flow from operations of USD 118 million. 44% of it went to capital expenditures, almost — exactly — just shy of 50%, 49% has gone to the various form of stakeholder returns, and the remaining 7%, this wedge here is the part that’s built up cash and working capital for our future financial flexibility.
So our organic growth plan, again, we’ve got a near-term goal here of getting to 18 million cubic foot equivalent a day or 3,000 barrels of oil equivalent per day with a longer-term vision of basically doubling that. The growth plan to come from really a couple of key areas.
We’ve got our existing platform of producing assets with our Caburé unit, which you can see in the center of the map sheet here. We did expand the gas plant last year up to 18 million cubic feet a day plus depending on the gas specification that we’re putting through there. And we are looking to further expand the unit production capacity here as we drill some additional wells next year with our partner. The second part of this is really this key asset that we have immediately to the north of that, which is our Murucututu project. We’ve already pipeline connected that in and put all the production facilities in place so that we can now crystallize the value associated with this asset.
And one of the things we’ve always talked about this as a Gomo Formation opportunity, and we’ve got some reserves and contingent and prospective resource assigned to that. And it’s important to remind people that, that just relates to the Gomo Formation. And something more recently that we’re quite excited about is the result that we had with our 183-A3 well, which Adrian is going to walk you through.
But it’s important to recognize that, that was drilled as a Gomo development well, but it also had this Caruaçu exploration potential. So when you look at the result, about 12 meters of the net pay that we see in that well relates to the Gomo, but 116 meters of potential net pay relates to this Caruaçu.
So we’re really excited about that. It’s on the same well pad as our production facility. So with success, we can get that tied in right away. And this has the potential, again, with success, to be a really important part of our plan going forward and could be quite important for us and our shareholders.
Yes. So as Corey mentioned, we’re — we finished drilling our 183-A3 well last month. This is a 100% working interest well into the Murucututu field, and we were quite excited to see the 116 meters of net pay in the Caruaçu. So on the line here on the screen, we see the number of net pay sections within the Caruaçu section. So at this point, we’re mobilizing the equipment and we’ll go through and complete each of these zones and hopefully build them on to production with the intent of having this thing on production by the end of the year.
Like Corey said, we’ve pre-invested in the infrastructure here. So this should be tied in. It’s 10 meters away from the pipeline, and we’ll start to crystallize the value here as well. This gives us a regional overview of the Caruaçu and where it lies within the context of the other producing wells in the basin. So our well we’re talking about here at Murucututu is right in the middle of the geological cross-section, the seismic section there.
And this well and the structure is down dip of the Caburé field, which is our main producing asset, down dip and across the fault here. The other field to the north is Miranga, which is one of the larger gas-producing fields in the base, and to the south is another large historical field called Jaquipe. So we’re really looking forward to tying this well in, putting it on production and continuing the reservoir exploitation here at the Caruaçu structure.
All right. Thank you, Adrian. So just in summary, I think Alvopetro certainly continues to offer a pretty attractive investment proposition, no matter what your focus is. We’re delivering some pretty strong results, obviously, very attractive gas pricing, industry-leading operating margins. We’ve got a clean balance sheet with strong free cash flow generation capacity, and that will help support this — supports this disciplined capital allocation model that we’ve got to balance reinvestment, organic growth and stakeholder returns.
For value investors, we’re trading at about 2/3 of our 2P NPVs. Again, none of this Caruaçu potential that Adrian reviewed is reflected in any of our reserves or reserves reports. For yield investors, a 9% dividend yield paid quarterly in U.S. dollars. And then for growth investors, we’ve got a pretty exciting organically funded capital program with a lot of potential, especially when you consider it relative to our existing market cap and enterprise value.
So with that, I think we’ll start the question-and-answer period.
A – Alison Howard
Sure. The first question relates to sales volumes. Sales volumes were much lower in Q3 but seem to have come up in October. Can we expect the rest of Q4 and early 2024 to continue at similar rates to October?
Yes. So really, this is a function of the demand in the basin and how are offtakers managing their portfolio of gas. Right now, Bahiagás has been asking for as much gas as we can basically give them. So I think if we had our 183-A3 well on production today, we’d be able to be selling all of that. So our expectation is that this was a temporary thing. It’s not to say it couldn’t happen again. But our expectation is that we’ll be able to sell all that.
How often is the Bahiagás contract renewed or adjusted for demand? Are there any options available to sell or export to additional buyers in the event Bahia doesn’t increase our volumes?
Yes. No — so that’s a good question. Typically, Bahiagás is looking at commitments on an annual basis in their portfolio from a firm perspective. The firm component of our supply does — if we were ever to have an issue with a well or a facility, it can attract supply failure penalties. So the way we’ve been managing that is having a component of firm and a component of flexible or interruptible gas that gives us more flexibility.
Typically, Bahiagás has been taking all that. We’ve had this one exception in the month of September effectively. So that’s something we’ll look at. We have the ability to increase — so from a strategic perspective, what we’re doing is we want to add as much 100% working interest production as we can. So that no matter what’s happening with the production from the unit at Caburé, we have the ability, step one, to be at this 3,000 BOEs a day or 18 million cubic foot a day rate.
So once we get enough — all that capacity in place, then we can be in a position to increase our firm nominations within our contract up to that level. So that would increase kind of the insurance or base level at which we would get paid because also in our contract is a mechanism where there’s take-or-pay payments that happen with Bahiagás.
So in the event that they took less than the threshold within our contracts, we get paid for that regardless. So again, strategically, that’s the plan, build enough capacity, increase our firm volumes, and then in addition to that, build some extra flexibility around exploring alternative markets. So we are a few hundred meters away from the [ main tag ] connection in the basin.
There are some other offtake ideas that are out there that could realize some attractive netbacks as well. So we’re pursuing all that. But in fairness, we’ve got this strategic connection directly into the Bahiagás distribution network right at our plant site. And that creates a big advantage for the end consumers and for Alvopetro and for Bahiagás.
So I think it’s in everyone’s interest to maximize the amount of locally produced gas that goes through that city gate as opposed to the alternative is importing it from LNG, importing it from Bolivia, bringing it from the offshore pre-salt, and there’s a bunch of transportation and other costs that get embedded effectively in the gas price when that happens.
So we think we’re well positioned.
The next question, what is the expected CapEx for Q4 of this year? And where will it be spent?
Yes. We don’t really provide CapEx dollar guidance, but our activity levels — after our Bom Lugar result, we decided — the rig had a commitment with another provider. So the rig’s moving — in the process of moving to do that commitment. So really, our lingering capital commitments are mostly associated with completing the 183-A3 well.
And then you’ll see a drop in capital expenditures here while we digest those results and get ready to restart the drilling portion, which is the most capital-intensive portion of our capital program. Practically speaking, that probably doesn’t happen until, at earliest, later in the first quarter.
The next question is around the results from 183-A3 and the positive surprises that we’re seeing in the Caruaçu. Do you want to comment on that further? And what are the plans to appraise this?
Yes. So if you look at the porosity of this — so first of all, the wells at Caburé are highly productive. It is a bit shallower, so we would expect better permeability at the shallower depth. But this is quite a prolific formation. The logs look quite good.
We’ve got some of those intervals that Adrian pointed to that we’re going to complete. Have porosities up to 15%. So we’re optimistic. We’re not going to put out a bunch of — we’re on the cusp of testing this. So we’re not going to put out guidance on what we think it might be.
I think we’re just going to ask people to be patient, and we’re going to get that news quite quickly. But the appraisal plan is complete these zones, put it on production. We can map the resource over — on seismic over a pretty nice area here. It has the potential to be quite material for us, but it’s one step at a time. We need to test it, produce it.
We’ll evaluate those results. And then we’re in the middle of permitting a new drilling pad location that would allow us to access all of the up dip locations. So what Adrian didn’t talk about, but it was on that slice of 3D seismic, you can see between the fault and where we drilled the well into the Caruaçu, there’s room for — to go up dip another 120 meters.
So even just from that well to the up dip crest of the structure by default, there’s almost 300 acres of land in there and 120 meters up dip. So that in itself could be material, and then the various sands probably have different aerial extents, but that’s something that would be delineated with additional drilling.
The other nice thing is a big chunk of the wells that we had planned to target the Gomo development, a good portion of those drill right through the Caruaçu as well. So it’s nice to be able to have multizone targets.
The next question, just shifting gears a bit. Can you take us through the accounting of the Bahiagás take-or-pay shortfall going forward? So yes, I didn’t comment on this earlier. We did have — when I was discussing the accounting results. We did have Bahiagás take-or-pay kick in, in the month of September because they were below the firm volumes.
That’s basically just a prepayment of gas. So what happens is it does not get reflected as sales until the volumes actually get delivered. So we get effectively the cash from Bahiagás, and that’s offset with, we call it other liabilities, but it’s essentially unearned revenue. And then as the gas gets delivered, the revenue gets recognized at that point, and then they get a reduction in their invoice for the portion that’s applied against that prepayment. So it’s relatively straightforward.
It’s — with production at these rates, we do expect that, that September amount will get recovered rather quickly. And yes, I think I answered that, but if you had any further questions on that, just maybe shoot me a note off-line and we can go through it. The next question is around Bom Lugar. Are there still plans for a follow-up development well, BL-07, at Bom Lugar?
Quite frankly, we weren’t happy with the results from that. So right now, there’s no plans, but we are going to continue to evaluate the production from that well. We’re going to look at alternatives potentially to stimulate it, but the capital plans are on hold right now.
Back to Murucututu. Are there still plans to get to 5 million cubic feet a day in 2024? Are the plans still on track for that? And what is the timing for further Gomo development wells?
Yes. So a lot of that is — a good chunk of that is actually a function of the test results that we get from this upcoming test, and that will help define a little bit better on a per well basis what we might expect from drilling new wells. We then would expect to use that to map out our capital program for next year.
So that will impact the timing. But again, dependent on those — the well results — I’m not sure where the 5 million a day target came from, but we think this can be, along with the Gomo, a big part of our growth story going forward.
And then the next couple of questions are around the share buyback. Has it started? And given — considering the capital program to date, corporate discount to PV10 and increasing share count, are we anticipating a reallocation of some 2024 capital spending towards share repurchase?
Yes. So the short answer is no, we haven’t used it. I think you saw from the pie, since inception, we’ve been pretty good about almost allocating the entire 50%, as originally envisioned, to the stakeholder return bucket. Going forward, we want to get this well test result because that can help define what our capital portion of the equation looks like. It helps define what our cash flow projections going forward look like. And then we can balance that 50% of the pot as deemed prudent between dividends and share buybacks.
Okay. And with that, there are no further questions.
All right. Well, as usual, feel free to call us at any time, and we’re happy to talk to you and answer any additional questions you might have, and thank you for joining us today. We look forward to updating you after our Q4 results. Thank you.