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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
[Call Starts Abruptly]
I am Corey Ruttan, President and Chief Executive Officer. And once again I'm joined by Alison Howard, our Chief Financial Officer; and Adrian Audet, our Vice President of Asset Management.
Good morning, everyone. Just a couple of administrative matters before we begin. We are recording this webcast today and there will be a copy of it available on our website later on this afternoon. We are hosting a Q&A session. So if you are participating via Zoom on your computer or your phone, you can submit your questions through the Q&A button on Zoom and we will get to that at the end of our presentation. If you are dialing in, you can submit your questions to socialmedia@alvopetro.com.
And lastly, we will be going through some non-GAAP measures and forward-looking statements. So I encourage you to review all of our cautionary statements at the end of our corporate presentation, which is available on our website.
Alright. Thank you, Alison. So just to talk a little bit about our production. Since coming on production on July 5, 2020, I think we have posted some pretty strong results. You can see our first couple of quarters of coming on production and our most recent few months, we have been pretty much right in line with the pre-commercialization expectations that we set, which was equal to the firm sales volumes within our Bahiagás sales contract and also equal to our share of the Caburé unit production at roughly 1,800 barrels of oil equivalent per day. The period in between there, you can see, we were able to significantly exceed those production levels just because we were able to nominate for more than our working interest share of the production from the Caburé unit. We also expanded our gas plant last year. So that allowed us to increase our production further there. So going forward, we will focus on this a little bit.
Our strategy is to add more 100% working interest production from our near-term capital program, so that we can maximize the throughput through our gas plant and really get back up to and hopefully above the levels that you saw in some of the more recent quarters there. We are looking to add 100% working interest natural gas production from our Murucututu project, as well as an oil component from our recent Bom Lugar success that we will talk about later in the presentation.
Just to talk again about our gas sales agreement. We just had a price reset under our agreement. A reminder, it gets reset twice a year, every February 1st and August 1st. Our price formula is based on three different international benchmark prices, and those are the gray dash lines that you see on this graph. So there is Henry Hub Natural Gas in the U.S., NBP Natural Gas in the UK, and Brent Oil Equivalent. And you kind of blend those together and average them over a period of time and the net effect is our realized price, which is the darker or thicker black line that you see there. We also have a floor and a ceiling within our contract, that's the red and the green lines that you see there. And both of those escalate based on U.S. inflation. So left of the red dash line that you see there is all the historical pricing and right of that is the forecast pricing.
We are using inflation estimates for this year of 3% in the U.S. and 2% thereafter. The benchmark price forecast that you see right at that line are based on the August 7th future strip pricing. And the net effect of all that is you can see the black line. We are expected to remain at the ceiling within our contract out through to -- well into 2026 that you see there.
So, just talk about our realized price. In the second quarter, we realized an average over the quarter of $12.86 per Mcf. And with that most recent price redetermination effect of August 1st of this year, our price reset up to US$13.25 per Mcf.
So yes, just building off of what Corey was speaking to there, we had our highest realized sales price in the quarter due to our gas price being at the ceiling, price in our contract, so that $12.86 per Mcf overall. Our realized sales price increased to $77.41. So an increase of almost $4.50 on a per barrel of oil equivalent. And then what you see is our operating netback, which is the green bar that measures our operating profitability per barrel of oil equivalent was a record again this quarter at $69.61, which is $3 above what we achieved in Q1. So that's attributable to that higher price that we realized in the quarter. Our royalties remain low at $1.97 per Boe, about 2.5% of our realized sales price. Our operating costs, our production expenses in the gray at $5.83. Those were higher this quarter. The majority of our costs are fixed in nature. So with that reduction in production in Q2, you saw our cost per Boe go up. But despite that, we still achieved record netbacks in Q2.
And from a profitability -- profit margin perspective, again, that's 90% of our realized sales price is profit there on operating netback, which is quite remarkable and what we like to say best-in-class among other entities, and we show that here. So comparing to other Latin American energy producers and some North American natural gas weighted companies that have released Q2, the average net margin among those is 60% and Alvopetro at 90%, that's 50% better. And that translates into very high profits overall on this production and the reason we're in Brazil. And that highlights the strength of the fiscal regime there, especially when you consider the low tax rate that we have until 2030 of 15.25% on our natural gas profits.
And then moving on to funds flow. So yes, we did see a decrease in our funds flow from Q2 that's mainly because of that 29% reduction in production in the period. So despite those higher prices, our sales volumes were down, partially offset by lower royalties and lower current tax and overall funds flow of just over $11 million in the quarter, which is still quite amazing for Alvopetro on that production.
Similarly on the net income with those lower funds flow, our net income also decreased in the period, but that was partially offset by some reduced depletion depreciation expenses and then lower current and deferred tax and then also higher foreign exchange gains in the period. So overall net income of just under $10 million in Q2.
From a balance sheet perspective, we continue to have a very strong balance sheet. Again, we are debt free as of last September. Our working capital, we did see a slight decrease from Q1, we did have more capital spending in the period, but still very strong at just over $18 million as of June 30th.
Alright, thank you Alison. So just talk about our dividend, we did introduce the dividend back in the third quarter of 2021. You can see that we've been able to increase that three times now, and we're paying currently US$0.14 per share quarterly. That translates into a current yield of around 7.4%. And we're pretty proud that we can say that we've already returned US$27 million to shareholders or the equivalent of the US$0.76 per share back to our shareholders over this period of time.
So one of the things we always talk about -- and this is something we developed many years ago, long before we even came on production, is just a stakeholder return model where we're looking to reinvest roughly half of our cash flows and growing our business and returning the other 50% to stakeholders. So if you focus on the bar chart on the top left, what you see there is our cash inflows are the green line with the black dots. Like Alison said, in the second quarter of 2023, we had cash flow of $11 million. And then each of the individual stacking bar charts there represents our cash flow -- cash outflows during each quarter. So you can see in the first kind of year or 15 months of production, we really were focused on prioritizing our debt repayment that Alison showed you. That's the green crosshatch bars that you see there and very little in the yellow, so not much capital expenditures. And we were able to do that because we pre-invested all the capital in our Caburé project and we didn't have a lot of need to be spending any money during that period of time.
The strong results that you've seen did allow us to start the dividend, I think, ahead of what we originally would've expected, and that's in the dark green bars that you see there, starting in Q3 of 2021. And then more recently you can see a more investment happening in our organic growth that -- that's the yellow bars that you see on there.
On the pie chart on the top right, this now measures exactly -- almost exactly three years of being on production from our project. You can see about 38% of the cash flow has been reinvested. Almost exactly or just shy of 50% has gone out to stakeholders in the various forms that you see in green. And over the first three years of operations, we've actually had funds flow from operations of US$109 million now. So pretty proud of this.
Speaking of the yellow bars that you saw on that chart, we're really quite focused on our next phase of growth here. We've got a near term goal of getting to the 18 million cubic foot equivalent per day level or roughly 3,000 barrels of oil equivalent per day. The growth is planned to come from a combination of areas, from our core existing base of operations. Like we said, we expanded the gas plant last year. Our goal with that target is to get that full and then ultimately with a goal of doubling that again. In addition, at the unit, we are looking to drill some additional development wells this year and further expand the unit productive capacity, which has been performing quite well.
Our two main growth assets, the first of which is our Murucututu project, again 100% working interest. This is a project that sits immediately north of our core Caburé asset base. All of the infrastructure is now in place to really start a multi-year development program that we have got planned for this asset. We did complete the stimulation of the 197(1) well and brought that on production in May. We talked about that in some detail on our last earnings call. And I think that was a pretty big milestone for us, and we are now in a position that we can start drilling fit-for-purpose wells. We have spun our first one of those, the 183-A3 well. We just spud that in July. So looking forward to results on that.
And then we also recently announced an exciting result from our BL-6 well on our Bom Lugar block and we are just in the process of getting ready to complete and test and bring that well on production here. And I will ask Adrian talk a little bit more about we found here.
Thank you, Corey. Yes. So this Bom Lugar 6 well, we are quite excited about it. The results you can see on the screen here, we had higher porosity and higher net pay than we were expecting going into this project. We are looking to begin testing and then put this well on production to our existing production facility here in the third quarter. And as we get to those results, we will be planning follow-up location, start BL-7 from the existing surface location and keep you updated.
Thank you, Adrian. So just in summary, we certainly think Alvopetro continues to offer a pretty attractive investment proposition no matter what your investing focus is. We have been delivering strong results. We have got attractive gas pricing and leading operating profit margins. Our clean balance sheet and free cash flow generation capacity really helps underpin our more balanced and disciplined stakeholder return model that we talked about. For value investors, we are trading at about three quarters of our 2P NAVs. For yield investors, a yield over 7%, with dividends paid in U.S. dollars quarterly. And for growth investors, I think, we are in the middle of implementing a pretty exciting and organically funded capital program. And if you look at the potential of what we are targeting there relative to our current enterprise value, I think it becomes even more exciting.
So with that, I think we are ready to start the question-and-answer period.
Sure. So the first question is with respect to production expectations. What are production expectations for the second half of 2023? Do you expect partner nominations to continue at the same levels?
So just given the nature of our company, we don't typically give out production guidance per se. But what I can say is, we are working with our partner to increase those nomination levels, but we are planning our budget -- our cash budget based on assuming that we are staying at these production levels with a strategy of adding a 100% working interest, natural gas production from Murucututu and a 100% working interest oil production from our Bom Lugar property. So our expectation is to try to get back up to our near-term goal of that 18 million cubic foot equivalent over the next few quarters.
And do you have specific guidance on what production contribution is expected from Murucututu and Bom Lugar?
Yes. Again, we've got in our corporate presentation kind of a typical type well for our Murucututu wells. We are looking forward to the completion of our next well here, because we're doing it in a way that we can really optimize the stimulations and maximize the results from that.
So I think, we'd like to kind of be able to show what that looks like, and then hopefully that's a model for the kind of the base going forward. And frankly, it's always a continuous improvement type process for these types of opportunities.
For our Bom Lugar, well, again, we're just about to complete that and put that on production. So we're going to have actual news pretty soon. The only thing we'll probably -- we can provide guidance on is what our reserve evaluators assumed in their 2P reserve forecast. The first year of production from that well from these formations, they had assumed 200 barrels a day average for the first year approximately.
What is the second half of 2023 CapEx expected to be and how will it be allocated?
Yes. So the main projects that we have, it will really depend on the pace of drilling and completions. But at our current pace, we would expect similar spending levels going forward. So the focus right now is on drilling the 183-A3 well, and completing the BL-6 well. Then we'll have -- our current plan is to drill a follow up well off of the same 183-A3 well pad for a second Gomo well. And then depending on the timing of that, we may start an additional well closer to the end of the year. So that's kind of how it's balanced.
The other thing we didn't talk about is the 183-A3 well is also targeting some shallow exploration potential in the Caruaçu Formation. So that's the same formation that is the main producer from our Caburé unit. So if we have success there, it's quite possible that we shift our capital program around as well. So it's really dependent on the results that we see over the coming quarters.
In February, the gas sales agreement set gas prices at $11.88 per Mcf or approximately $71.28 per Boe. This quarter's realized price was over $77. Does the higher pricing reflect higher BTU content or is there another explanation?
Want me to take that?
Go for it.
So yes, when we published our expected natural gas price, recall that it's set locally in local currency. So we do disclose an estimated equivalent in U.S. dollars that's based on that natural gas contracted price, but it takes into account an estimated foreign exchange rate. I think the $11.88 was disclosed prior to the sales tax credits that we also get. So that's why it ended up being like closer to $13. So that was part of it, is their sales tax credits, which increases our overall realized price. And then the other component is the foreign exchange.
So the Brazilian currency, the real appreciated in comparison to the time that we would've disclosed the -- I think we would've used the February’s -- January 31st spot price or the February average price in determining that Mcf amount. So the currency appreciated relative to that. So in equivalent U.S. dollars, our realized price was higher. Hopefully that makes sense. But I think on the heat content basis, it's been in line with expectations at around, is it 7% Adrian?
Yes.
Yes.
Above contract, yes.
Would you explain the decline in royalty costs again, and it's $2 per Boe, a good rate to expect going forward?
I can take that one again. So, our royalty rate, generally speaking on most of our fields is about 8.5% in Brazil of our production. But in Brazil, the natural gas volumes that is, the royalties are based on the value of the raw unprocessed natural gas. So -- and they use a reference price for that and it's closer to Henry Hub. So it's more dependent on what you expect Henry Hub to be relative to what we think are -- what our contracted price is, or our forecasted contracted price at the ceiling. So I think our ceiling price is $10.60 something per MMBtu. Henry Hub was, I think 2.16 per MMBtu on average in Q2. I think it's closer over 2.50 now. I didn't -- I haven't looked in the last few days, but -- so it's more a function of that taking into account our 8.5%. So hopefully that makes sense. So yes, if Henry Hub stays at these levels, then our royalty rate could be in the 2.5%, 3% on an effective basis of our realized sales price. But it just really depends on how our contracted price moves and how Henry Hub moves on the natural gas.
On our oil and condensate, it's more based on the sales price. So it more ties to Brent from that perspective.
When do you expect to get production to near the capacity of the 18 million cubic feet per day?
Yes, I think we answered that question earlier with -- this is really just a function of the timing of drilling the wells and completing them and in what order we drill the wells. So, I think, yes.
So we have a couple of questions kind of in line with that. Do you have any timelines on when you expect to double the gas plant or build a second processing plant?
Yes. So again, I think we -- let us get a couple of more wells drilled in into our Gomo Project here or our Murucututu project. We do show in the corporate presentation kind of indicatively call it a four-year development plan that would target the 2P reserves and the contingent and prospective resource that we have. We paced that in a way that we feel that could be organically funded. And if we can achieve those types of results, that gives you a sense on the ramp up of that asset alone. So that gives you a good sense. And what it shows you is that over that kind of three to four year period, earlier than the fourth year, but within that time period, that asset alone has the potential of delivering 18 million cubic feet a day. So then layer that on top of whatever we're producing from the Caburé unit. And we do disclose that as MCF equivalent. So, hopefully we've got some exciting results from our Bom Lugar oil project to layer in there as well. So…
When will the 182-C and 183-B have a re-stimulation or a stimulation?
Yes, no, we're just continuing the evaluation of that and evaluating what the best enhancement is, and then we will schedule that in the context of all of our other activity and our rig availability, et cetera. So practically speaking, it's probably something later this year.
You have a lot on your plate this year. Does this mean any M&A is not a priority at this time?
Well, we don't typically comment on M&A. I think if there is the right opportunity, we will obviously pursue it. I think from a shareholder value perspective, I think if we can fund these capital programs organically and they are as effective as we hope that they're going to be, I think we have the ability to add a lot of shareholder value by just focusing on the opportunities we have in front of us.
And that is all we have right now.
All right. So once again, thank you everyone for joining. And if you have any questions after the call, feel free to reach out to any one of us. And again, thank you for your support, and we look forward to updating you next quarter.